UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
Securities Exchange Act of 1934
Date of Report
(Date of earliest event reported):
December 31, 1997
Commission Registrant; State of Incorporation; IRS Employer
File Number Address; and Telephone Number Identification
No.
1-3672 CENTRAL ILLINOIS PUBLIC SERVICE COMPANY 37-0211380
(An Illinois Corporation)
607 E. Adams Street
Springfield, Illinois 62739
217-523-3600
1-10628 CIPSCO INCORPORATED 37-1260920
(An Illinois Corporation)
607 E. Adams Street
Springfield, Illinois 62739
217-523-3600
Item 2. Acquisition or Disposition of Assets
On December 31, 1997, following the receipt of all required
State and Federal regulatory approvals, Union Electric Company ("UE")
and CIPSCO Incorporated ("CIPSCO"), parent company of Central Illinois
Public Service Company ("CIPS"), combined to form Ameren Corporation
("Ameren") with the result that the common shareholders of UE and
CIPSCO became the common shareholders of Ameren and Ameren became the
owner of 100% of the common stock of CIPS and UE. Pursuant to an
Agreement and Plan of Merger dated as of August 11, 1995 between
(among others) UE, CIPSCO and Ameren, each outstanding share of UE
common stock is to be exchanged for one share of Ameren common stock
and each outstanding share of CIPSCO common stock is to be exchanged
for 1.03 shares of Ameren common stock.
Pursuant to Rule 12g-3(c) promulgated under the Securities
Exchange Act of 1934, as amended (the "Exchange Act"), as a result of
consummation of the foregoing transactions, Ameren common stock shall
be deemed to be registered under Section 12(b) of the Exchange Act.
A copy of the press release with respect to completion of
the transaction is attached as Exhibit 99-1 to this report.
Item 7. Financial Statements and Exhibits
The following documents, previously filed with the
Securities and Exchange Commission by Union Electric Company (File No.
1-2967), CIPSCO Incorporated (File No. 1-10628), Ameren Corporation or
Central Illinois Public Service Company (File No. 1-3672) pursuant to
the Securities Exchange Act of 1934, as amended, are hereby
incorporated by reference:
1. Union Electric Company's Annual Report on Form 10-K for the
year ended December 31, 1996.
2. Union Electric Company's Quarterly Reports on Form 10-Q for
the quarters ended March 31, June 30, and September 30, 1997.
3. Union Electric Company's Reports on Form 8-K dated December
16, and December 31, 1997.
4. CIPSCO Incorporated/ Central Illinois Public Service
Company's Annual Report on Form 10-K for the year ended
December 31, 1996.
5. CIPSCO Incorporated/ Central Illinois Public Service
Company's Quarterly Reports on Form 10-Q for the quarters
ended March 31, June 30, and September 30, 1997.
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6. Central Illinois Public Service Company's Current Reports on
Form 8-K, dated March 20, June 1, November 24, and December 16,
1997.
7. CIPSCO Incorporated's Current Reports on Form 8-K, dated
March 20, November 24, and December 16, 1997.
8. Ameren Corporation's Current Report on Form 8-K, dated
December 31, 1997.
Exhibits:
All exhibits are listed in the Exhibit Index on Page 4.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
CIPSCO INCORPORATED
(Registrant)
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
(Registrant)
/s/ Robert C. Porter
_______________________________________
Robert C. Porter
Treasurer and Assistant Secretary
of each Registrant
Date: January 2, 1998
-3-
Exhibit Index
Exhibit No. Description
2 Agreement and Plan of Merger dated as of August 11, 1995, by
and between UE, CIPSCO, the Company and Arch Merger, Inc.
(incorporated by reference to Form S-4, Annex A, dated
November 13, 1995 (File No. 33-64165).
27-1 Ameren Corporation Financial Data Schedule - Period ending
December 31, 1996. *
27-2 Ameren Corporation Financial Data Schedule - Period ending
September 30, 1997. *
99-1 Ameren Corporation News Release of Ameren Corporation, dated
December 31, 1997.
99-2 Ameren Corporation Supplemental Consolidated Financial
Statements.
99-3 Ameren Corporation Supplemental Consolidated Condensed
Quarterly Financial Statements.
* Incorporated by reference.
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One Ameren Plaza
1901 Chouteau
St. Louis, Mo 63103
AMEREN [LOGO] News Release
Contact:
Media:
Susan Gallagher
(314) 554-2175
Investor:
Lynn Barnes
(314) 554-4829
UNION ELECTRIC COMPANY AND CIPSCO INCORPORATED COMPLETE MERGER TO CREATE
AMEREN CORPORATION
St. Louis, MO, and Springfield, IL, Dec. 31, 1997--- Union Electric Company
and CIPSCO Incorporated two financially strong Midwest utilities -- today
announced the completion of their merger.
The combination creates Ameren Corporation (NYSE: AEE). With assets
of approximately $9 billion, Ameren is parent of Union Electric (now known
as AmerenUE) and Central Illinois Public Service Company (now known as
AmerenCIPS).
Ameren companies serve 1.5 million electric customers and 300,000
natural gas customers in a 44,500-square mile area of Missouri and
Illinois. The new holding company and AmerenUE are based in St. Louis;
the headquarters of AmerenCIPS remains in Springfield, IL.
With the completion of the merger, shares of the new company began
trading on the New York Stock Exchange. The two companies signed a
definitive merger agreement in 1995 in a transaction valued now at
approximately $1.4 billion. The market capitalization of Ameren is
approximately $5.3 billion.
"It is an understatement to say that we are extremely pleased our
merger has been approved. Our employees have demonstrated creativity and
dedication to make this merger a reality," said Charles W. Mueller,
chairman, president and chief executive officer of Ameren Corporation. "As
we said two years ago and we believe even more firmly today, this merger
brings together two high quality, low-cost energy providers who have
customer-focused philosophies and a solid position in their respective
markets."
CIPSCO President and Chief Executive Officer Clifford L. Greenwalt,
who retires Dec. 31, 1997, cited the two companies' focus on their core
energy business and the $759 million in merger savings expected over the
next 10 years as strengths in an increasingly competitive environment.
Holders of Union Electric common stock receive one share of the new holding
company common stock (NYSE: AEE) for each Union Electric share (NYSE: UEP)
they hold. Holders of CIPSCO Incorporated common stock (NYSE: CIP) receive
1.03 shares of the holding company common stock. (CIPSCO Incorporated was
the parent company of Central Illinois Public Service Company.) Upon
completion of the merger, Ameren has approximately 137 million common
shares outstanding.
Ameren is expected to initially adopt Union Electric's annual common
share dividend payment level (UE's current annual dividend is $2.54 per
share).
The new holding company's 15-member board of directors includes 10
members from Union Electric, with Mueller as chairman of the board, and
five from CIPSCO, including Greenwalt.
The final of six regulatory approvals for the merger came from the
Securities and Exchange Commission on Dec. 31. Other regulatory approvals
were obtained from the Federal Energy Regulatory Commission, the Illinois
Commerce Commission, the Missouri Public Service Commission, Hart-Scott
Rodino Filing/Federal Trade Commission and Department of Justice, and the
Nuclear Regulatory Commission.
Shareholders of both companies approved the agreement Dec. 20, 1995.
The preferred stock of Union Electric Company and Central Illinois
Public Service Company remains outstanding.
# # #
Exhibit 99-2
SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
OVERVIEW
Ameren Corporation (Ameren) is a newly created holding company which will
be registered under the Public Utility Holding Company Act of 1935 (PUHCA).
In December 1997, Union Electric Company (AmerenUE) and CIPSCO Incorporated
(CIPSCO) combined to form Ameren, with AmerenUE and CIPSCO's subsidiaries,
Central Illinois Public Service Company (AmerenCIPS) and CIPSCO Investment
Company (CIC) becoming wholly-owned subsidiaries of Ameren (the Merger).
In addition, Ameren, as a result of the Merger, has a 60 percent ownership
interest in Electric Energy, Inc. (EEI), which is consolidated for
financial reporting purposes. Upon consummation of the Merger, the common
stockholders of AmerenUE and CIPSCO received one and 1.03 shares,
respectively, of Ameren common stock, par value $.01 per share, and became
common stockholders of Ameren.
The Merger is accounted for as a pooling-of-interests, and the Supplemental
Consolidated Financial Statements included in this Form 8-K, in lieu of pro
forma financial statements as required by Article ll, "Pro Forma Financial
Information" of Regulation S-X, are presented as if the Merger were
consummated as of the beginning of the earliest period presented. However,
the Supplemental Consolidated Financial Statements are not necessarily
indicative of the results of operations, financial position or cash flows
that would have occurred had the Merger been consummated for the periods
for which it is given effect, nor is it necessarily indicative of the
future results of operations, financial position or cash flows.
References to the Company are to Ameren on a consolidated basis; however,
in certain circumstances, the subsidiaries are separately referred to in
order to distinguish between their different business activities.
RESULTS OF OPERATIONS
Earnings
Earnings for 1996, 1995, and 1994 were $372 million ($2.71 per share), $373
million ($2.72 per share), and $391 million ($2.85 per share),
respectively. Earnings and earnings per share fluctuated due to many
conditions, primarily: weather variations, electric rate reductions,
competitive market forces, credits to electric customers, sales growth,
fluctuating operating costs, including the Callaway Plant nuclear refueling
outages, merger-related expenses, changes in interest expense and changes
in income and property taxes.
Electric Operations
The impacts of the more significant items affecting electric revenues and
operating expenses during the past three years are analyzed and discussed
below:
Electric Revenues Variations from Prior Year
(Millions of Dollars) 1996 1995 1994
Rate variations $(20) $(14) $ -
Credit to customers (15) (33) -
Effect of abnormal weather (68) 63 (45)
Growth and other 107 51 50
Interchange sales 51 (13) (11)
EEI (2) (76) 25
___ ___ ___
$ 53 $(22) $19
The increase in 1996 electric revenues was primarily due to a 4 percent
increase in kilowatthour sales over the prior year, partly offset by the
1.8 percent rate decrease for Missouri electric customers and the net
increase in Missouri electric customer credits recorded in 1996 versus
1995. See Note 2 - Regulatory Matters under Notes to Supplemental
Consolidated Financial Statements for further information. The
kilowatthour sales increase reflected strong economic growth in the service
area and increased interchange sales opportunities, partially offset by
milder weather during the period. Residential and industrial sales each
rose 2 percent over 1995, while commercial sales grew 3 percent and
interchange sales increased 9 percent.
The decrease in 1995 electric revenues was primarily the result of
decreased sales to the Department of Energy by EEI, a one-time $30 million
credit to Missouri electric customers, a rate decrease in Missouri, and a
13 percent decline in interchange sales due to decreased interchange sales
opportunities. See Note 2 - Regulatory Matters under Notes to Supplemental
Consolidated Financial Statements for further information. This decrease
was partially offset by increased retail kilowatthour sales, mainly due to
the unusually hot weather in the third quarter of 1995, compared to 1994,
and sales growth reflecting the Company's healthy service area economy.
Weather-sensitive residential and commercial sales increased 6 percent and
3 percent, respectively, over 1994, and industrial sales grew 2 percent.
The increase in 1994 electric revenues reflected growth in sales to
commercial and industrial customers of 3 percent each, partially offset by
reduced sales to residential customers of 3 percent, primarily due to
milder weather in the first and third quarters of 1994, compared to 1993.
Fuel and Purchased Power Variations from Prior Year
(Millions of Dollars) 1996 1995 1994
Fuel:
Variation in generation $43 $(10) $ 58
Price (14) 2 (73)
Generation efficiencies and other 2 3 (2)
Purchased power variation 2 9 (47)
EEI 23 (42) (3)
___ ___ ___
$56 $(38) $(67)
The increase in 1996 fuel and purchased power costs was driven mainly by
higher kilowatthour sales, partially offset by lower fuel prices due to the
use of lower cost coal. The decrease in 1995 fuel and purchased power
costs reflected decreased sales by EEI, partly offset by greater retail
kilowatthour sales during the hot 1995 summer and the need for replacement
power during the Callaway Plant's spring nuclear refueling outage. The
decrease in 1994 fuel and purchased power costs reflected lower fuel
prices, resulting from the increased use of low-sulfur coal at the
Company's fossil-fueled power plants. Higher generation, due largely to
the availability of the Callaway Plant resulting from the absence of a
refueling outage in 1994, was offset in part by reduced purchased power
costs.
Gas Operations
The increase in 1996 gas revenues of $37 million was primarily the result
of higher gas prices and increased sales due to colder weather.
Residential, commercial, and industrial dekatherm sales increased 13
percent, 17 percent and 7 percent, respectively, in 1996 versus 1995. Gas
revenues decreased $7 million in 1995 as a result of lower prices and lower
commercial and industrial dekatherm sales of 3 percent and 25 percent,
respectively, partly offset by a 2 percent increase in weather-sensitive
residential dekatherm sales from colder weather in 1995 versus 1994. In
1994, gas revenues decreased $21 million primarily as a result of decreased
sales due to milder weather and lower gas prices. Dekatherm sales to
residential and commercial customers decreased 8 percent and 6 percent,
respectively, compared to 1993, while industrial sales remained unchanged.
The $35 million increase in 1996 gas costs was primarily the result of a
combination of increased demand due to colder weather, coupled with an
increase in the price paid for gas in 1996 versus 1995. The decrease in
1995 gas costs of $20 million was predominantly due to lower gas prices in
1995, compared to 1994. In 1994, gas costs decreased $12 million primarily
due to milder weather and lower gas prices in 1994 versus 1993.
Other Operating Expenses
Other operating expense variations in 1994 through 1996 reflected recurring
factors such as growth, inflation, labor and benefit increases. In 1996,
other operations expenses increased $2 million primarily due to increases
in employee benefits, injuries and damages, and consulting expenses. In
1995, other operations expenses increased $7 million mainly due to
increases in labor and material and supplies expenses, as well as the
occurrence of several one-time costs, including costs relating to a
voluntary separation program and write-offs of system development costs.
These increases were partly offset by decreases in employee benefits,
injuries and damages and insurance expenses. The decrease of $24 million
in other operations expenses in 1994 is primarily the result of EEI
electing to record in 1993 a $25 million one-time charge in conjunction
with its adoption of SFAS No. 106, "Employers Accounting for Postretirement
Benefits Other than Pensions."
In 1996, maintenance expenses decreased $5 million primarily due to lower
scheduled power plant maintenance, partly offset by increased labor
expenses at Callaway and fossil plants. In 1995, maintenance expenses
increased $26 million, mainly due to scheduled power plant maintenance
expenses partially offset by reduced distribution system maintenance
expenses. Callaway Plant's maintenance expenses increased $17 million
primarily due to the spring 1995 nuclear refueling outage. Maintenance
expenses at other power plants increased primarily due to scheduled
maintenance outages. In 1994, maintenance expenses increased $12 million,
mainly caused by additional maintenance expenses at fossil plants and
greater tree-trimming expenses, partly offset by lower Callaway Plant
maintenance expenses (no refueling outage in 1994) and reduced labor
expenses.
Depreciation and amortization expense increased $12 million in 1996, $11
million in 1995 and $16 million in 1994, due to increased depreciable
property.
Taxes
Income tax expense from operations decreased $9 million in 1996 principally
due to lower pretax income. Income tax expense decreased $2 million in
1995 primarily due to lower pretax income partially offset by a higher
effective income tax rate. In 1994 income tax expense increased $26
million as a result of higher pretax income.
In 1996, other taxes charged to operating expenses increased $2 million due
to increased property and payroll taxes. In 1995, other taxes charged to
operating expenses increased $2 million due to increased gross receipts
taxes from greater electric revenues and increased property taxes. In
1994, other taxes charged to operating expenses rose $5 million due to
increased property taxes and greater corporate franchise taxes.
Other Income and Deductions
Miscellaneous, net increased $1 million for 1996, primarily due to reduced
merger-related expenses. Miscellaneous, net decreased $11 million for
1995, primarily due to increased merger-related expenses. Merger-related
expenses totaled $13 million and $14 million in 1996 and 1995,
respectively. See Note 1 - Summary of Significant Accounting Policies
under Notes to Supplemental Consolidated Financial Statements for further
information. Miscellaneous, net decreased $9 million for 1994, primarily
due to increased charitable contributions.
Interest
Interest expense increased $2 million for 1996 primarily due to a greater
amount of short-term debt outstanding, offset by lower rates on variable-
rate long-term debt. In 1995, interest expense declined $5 million as
decreases in other interest expense were partly offset by higher interest
rates on variable long-term debt. In 1994, interest expense increased $13
million generally due to a greater amount of total debt outstanding and
overall higher interest rates on variable-rate debt.
Balance Sheet
The $51 million increase in other current liabilities at December 31, 1996,
compared to December 31, 1995, was primarily due to the timing of the
payments of the $47 million Missouri electric customer credit. See Note 2
- - Regulatory Matters under Notes to Supplemental Consolidated Financial
Statements for further information.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $786 million for 1996,
compared to $792 million and $708 million in 1995 and 1994, respectively.
Cash flows used in investing activities totaled $481 million, $468 million,
and $485 million for the years ended December 31, 1996, 1995 and 1994,
respectively. Expenditures in 1996 for constructing new or to improve
existing facilities, purchasing rail cars and complying with the Clean Air
Act were $436 million. In addition, the Company spent $51 million to
acquire nuclear fuel.
The Company's need for additional base load electric generating capacity is
not anticipated until after the year 2013. Under Title IV of the Clean Air
Act Amendments of 1990, the Company is required to reduce total sulfur
dioxide emissions significantly by the year 2000. Significant reductions
in nitrogen oxide are also required. By switching to low-sulfur coal and
early banking of emissions credits, the Company anticipates that it can
comply with the requirements of the law without significant revenue
increases because the related capital costs are largely offset by lower
fuel costs. As of year-end 1996, estimated remaining capital costs
expected to be incurred pertaining to Clean Air Act-related projects
totaled $76 million. Construction expenditures are expected to be about
$370 million in 1997. For the five-year period 1997-2001, construction
expenditures are estimated at $1.7 billion. This estimate does not include
any construction expenditures which may be incurred by the Company to meet
new air quality standards for ozone and particulate matter, as discussed
below.
In July 1997, the United States Environmental Protection Agency (EPA)
issued final regulations revising the National Ambient Air Quality
Standards for ozone and particulate matter. Although specific emission
control requirements are still being developed, it is believed that the
revised standards will require significant additional reductions in
nitrogen oxide and sulfur dioxide emissions from coal-fired boilers. In
October 1997, the EPA announced that Missouri and Illinois are included in
the area targeted for nitrogen oxide emissions reductions as part of their
regional control program. Reduction requirements in nitrogen oxide
emissions from the Company's coal-fired boilers could exceed 80 percent
from 1990 levels by the year 2002. Reduction requirements in sulfur
dioxide emissions may be up to 50 percent beyond that already required by
Phase II acid rain control provisions of the 1990 Clean Air Act Amendments
and are anticipated to be required by 2007. Because of the magnitude of
these additional reductions, the Company could be required to incur
significantly higher capital costs to meet future compliance obligations
for its coal-fired boilers or purchase power from other sources, either of
which could have significantly higher operating and maintenance
expenditures associated with compliance. At this time the Company is
unable to determine the impact of the revised air quality standards on the
Company's future financial condition, results of operations or liquidity.
The United States and other countries are discussing possibilities for an
international treaty to address the issue of "global warming." The Company
is unable to predict what agreements, if any, will be adopted. However,
most of the proposals under discussion could result in significantly higher
capital costs and operations and maintenance expenditures by the Company.
At this time, the Company is unable to determine the impact of these
proposals on the Company's future financial condition, results of
operations or liquidity.
See Note 11 - Callaway Nuclear Plant under Notes to Supplemental
Consolidated Financial Statements for a discussion of Callaway Plant
decommissioning costs.
Cash flows used in financing activities were $296 million for 1996,
compared to $325 million and $226 million for 1995 and 1994, respectively.
The Company's principal financing activities during 1996 included the
redemption of $35 million of first mortgage bonds and $18 million of short-
term debt bank loans and the payment of dividends. In addition, on
December 16, 1996, AmerenUE issued $66 million of Subordinated Deferrable
Interest Debentures, 7.69 percent Series, due 2036. AmerenUE used the
proceeds to redeem certain series of preferred stock in January 1997.
The Company plans to continue utilizing short-term debt to support normal
operations and other temporary requirements. AmerenUE and AmerenCIPS are
authorized by the Federal Energy Regulatory Commission (FERC) to have up to
$600 million and $150 million, respectively, of short-term unsecured debt
instruments outstanding at any one time. Short-term borrowings consist of
bank loans (maturities generally on an overnight basis) and commercial
paper (maturities generally within 10 to 45 days). At December 31, 1996,
the Company had committed bank lines of credit aggregating $257 million (of
which $246 million were unused at such date) which make available interim
financing at various rates of interest based on LIBOR, the bank certificate
of deposit rate or other options. The lines of credit are renewable
annually at various dates throughout the year. At year-end, the Company had
$69 million of short-term borrowings.
AmerenCIPS has registration statements covering $200 million of first
mortgage bonds and medium-term notes filed with the Securities and Exchange
Commission (SEC). AmerenCIPS' mortgage indenture limits the amount of
first mortgage bonds which may be issued. At December 31, 1996, AmerenCIPS
could have issued about $480 million of additional first mortgage bonds
under the indenture, assuming an annual interest rate of 7.75 percent.
Additionally, AmerenCIPS' articles of incorporation limit amounts of
preferred stock which may be issued. Assuming a preferred dividend rate of
6.50 percent, the utility could have issued all $185 million of authorized
but unissued preferred stock as of year-end. AmerenUE has registration
statements covering $160 million of long-term debt filed with the SEC. In
addition, AmerenUE has registration statements filed with the SEC covering
$100 million of preferred stock. AmerenUE also has bank credit agreements
due 1999 which permit the borrowing of up to $300 million and $200 million
on a long-term basis. At December 31, 1996, no such borrowings were
outstanding.
Additionally, AmerenUE has a lease agreement which provides for the
financing of nuclear fuel. At December 31, 1996, the maximum amount which
could be financed under the agreement was $120 million. Cash provided from
financing for 1996 included issuances under the lease for nuclear fuel of
$44 million offset in part by $35 million of redemptions. At December 31,
1996, $106 million was financed under the lease. See Note 3 - Nuclear Fuel
Lease under Notes to Supplemental Consolidated Financial Statements for
further information.
RATE MATTERS
See Note 2 - Regulatory Matters under Notes to Supplemental Consolidated
Financial Statements for further information.
CONTINGENCIES
Subsequent to the completion of a contract restructuring with a major coal
supplier by AmerenCIPS, a group of industrial customers filed with the
Illinois Third District Appellate Court (the Court) in February 1997 an
appeal of the December 1996 order of the Illinois Commerce Commission (ICC)
which approved, among other things, recovery of the restructuring payment
and associated carrying costs (Restructuring Charges), incurred as a result
of the restructuring, through the retail fuel adjustment clause (FAC).
Additionally, in May 1997 the FERC approved recovery of the wholesale
portion of the Restructuring Charges through the wholesale FAC.
As a result of the ICC and FERC orders, AmerenCIPS classified the $72
million of the Restructuring Charges made to the coal supplier in February
1997 as a regulatory asset and, through October 1997, recovered
approximately $9.5 million of the Restructuring Charges through the retail
FAC and from wholesale customers.
On November 24, 1997, the Court reversed the ICC's order, finding that the
Restructuring Charges were not direct costs of fuel that may be recovered
through the retail FAC, but rather should be considered as a part of a
review of AmerenCIPS' aggregate revenue requirements in a full rate case.
Restructuring Charges allocated to wholesale customers (approximately 16
percent of the total) are not in question as a result of the opinion of the
Court. On December 8, 1997, AmerenCIPS requested a rehearing by the Court.
The Company is evaluating the impact of the Court decision on its financial
statements. The Company cannot predict the ultimate outcome of this
matter. If the Court's decision should ultimately prevail, AmerenCIPS will
be required to cease recovery of the Restructuring Charges through the
retail FAC, and could be required to refund any portion of those charges
that had been collected through the retail FAC. The Company is also
exploring other alternatives for recovery of the Restructuring Charges.
The Company is currently evaluating the unamortized retail portion of the
Restructuring Charges, which is currently classified as a regulatory asset,
to determine if it continues to meet the criteria for the existence of an
asset under Generally Accepted Accounting Principles (GAAP). If it is
determined that such criteria are not met, the unamortized balance of the
Restructuring Charges, approximately $36 million, net of tax, could be
charged to earnings. The Company is also evaluating the revenues
previously recovered in 1997 through the retail FAC to determine if a loss
contingency, as defined under GAAP, is required. Such loss contingency ($5
million, net of tax) could also be charged to earnings. See Note 10 -
Commitments and Contingencies under Notes to Supplemental Consolidated
Financial Statements for further information.
See Note 10 - Commitments and Contingencies under Notes to Supplemental
Consolidated Financial Statements for other material issues existing at
December 31, 1996.
DIVIDENDS
Common stock dividends paid in 1996 resulted in a payout rate of 88% of the
Company's earnings to common stockholders. Dividends paid to common
stockholders in relation to net cash provided by operating activities for
the same period were 42%.
The Board of Directors does not set specific targets or payout parameters
for dividend payments, however, the Board considers various issues
including the Company's historic earnings and cash flow; projected
earnings, cash flow and potential cash flow requirements; dividend
increases at other utilities; return on investments with similar risk
characteristics; and overall business considerations. It is currently
anticipated that the Company will initially pay dividends on its common
stock at AmerenUE's historical payment level, which was $2.54 per share on
an annual basis prior to the consummation of the Merger.
ELECTRIC INDUSTRY RESTRUCTURING
Changes enacted and being considered at the federal and state levels
continue to change the structure of the electric industry and utility
regulation, as well as encourage increased competition. At the federal
level, the Energy Policy Act of 1992 reduced various restrictions on the
operation and ownership of independent power producers and gave the FERC
the authority to order electric utilities to provide transmission access to
third parties.
In April 1996, the FERC issued Order 888 and Order 889 which are intended
to promote competition in the wholesale electric market. The FERC requires
transmission-owning public utilities, such as AmerenUE and AmerenCIPS, to
provide transmission access and service to others in a manner similar and
comparable to that which the utilities have by virtue of ownership. Order
888 requires that a single tariff be used by the utility in providing
transmission service. Order 888 also provides for the recovery of stranded
costs, under certain conditions, related to the wholesale business.
Order 889 established the standards of conduct and information requirements
that transmission owners must adhere to in doing business under the open
access rule. Under Order 889, utilities must obtain transmission service
for their own use in the same manner their customers will obtain service,
thus mitigating market power through control of transmission facilities.
In addition, under Order 889, utilities must separate their merchant
function (buying and selling wholesale power) from their transmission and
reliability functions.
The Company believes that Order 888 and Order 889, which relate to its
wholesale business, will not have a material adverse effect on its
financial condition, results of operations or liquidity.
In addition, certain states are considering proposals that would promote
competition at the retail level. In December 1997, the Governor of
Illinois signed the Electric Service Customer Choice and Rate Relief Law of
1997 (the Act) providing for utility restructuring in Illinois. This
legislation introduces price-based competition into the supply of electric
energy in Illinois and will provide a less regulated structure for Illinois
electric utilities. The Act includes a 5 percent residential electric rate
decrease for the Company's Illinois electric customers, effective August 1,
1998. The Company may be subject to additional 5 percent residential
electric rate decreases in each of 2000 and 2002 to the extent its rates
exceed the Midwest utility average at that time. The Company's rates are
currently below the Midwest utility average. The Company estimates that
the initial 5 percent rate decrease will result in a decrease in annual
electric revenues of about $13 million, based on estimated levels of sales
and assuming normal weather conditions. Retail direct access, which allows
customers to choose their electric generation supplier, will be phased in
over several years. Access for commercial and industrial customers will
occur over a period from October 1999 to December 2000, and access for
residential customers will occur after May 1, 2002. The Act also relieves
the Company of the requirement in the ICC's Order issued in September 1997
(which approved the Merger), requiring AmerenUE and AmerenCIPS to file
electric rate cases or alternative regulatory plans in Illinois following
consummation of the Merger to reflect the effects of net merger savings.
Other provisions of the Act include (1) potential recovery of a portion of
a utility's stranded costs through a transition charge collected from
customers who choose another electric supplier, (2) the option for certain
utilities, including the Company, to eliminate the retail FAC applicable to
their rates and to roll into base rates a historical level of fuel expense
and (3) a mechanism to securitize certain future revenues related to
stranded costs.
At this time, the Company is assessing the impact that the Act will have on
its operations. The potential negative consequences resulting from the Act
could be significant and include the impairment and writedown of certain
assets, including generation-related plant and regulatory assets, related
to the Company's Illinois jurisdictional assets. The provisions of the Act
could also result in lower revenues, reduced profit margins and increased
costs of capital. At this time, the Company is unable to determine the
impact of the Act on the Company's future financial condition, results of
operations or liquidity. (See Note 2 - Regulatory Matters under Notes to
Supplemental Consolidated Financial Statements.)
In Missouri, where 72 percent of the Company's retail electric revenues are
derived, a task force appointed by the Missouri Public Service Commission
(MoPSC) is investigating industry restructuring and competition and is
scheduled to issue a report to the MoPSC in 1998. A joint legislative
committee is also conducting hearings on these issues. Currently, retail
wheeling has not been allowed in Missouri; however, the joint agreement
approved by the MoPSC in February 1997 as part of its merger authorization
includes a provision that required AmerenUE to file a proposal for a 100-
megawatt experimental retail wheeling pilot program in Missouri. AmerenUE
filed its proposal with the MoPSC in September 1997. This proposal is
still subject to review and approval by the MoPSC.
The Company is unable to predict the timing or ultimate outcome of the
electric industry restructuring initiatives being considered in the state
of Missouri. In the state of Missouri, the potential negative consequences
of industry restructuring could be significant and include the impairment
and writedown of certain assets, including generation-related plant and
regulatory assets, lower revenues, reduced profit margins and increased
costs of capital. At this time, the Company is unable to predict the
impact of potential electric industry restructuring matters in the state of
Missouri on the Company's future financial condition, results of operations
or liquidity. (See Note 2 - Regulatory Matters under Notes to Supplemental
Consolidated Financial Statements for further information.)
INFORMATION SYSTEMS
The Year 2000 issue relates to computer systems and applications which
currently use two-digit date fields to designate a year. As the century
date change occurs, date-sensitive systems will recognize the year 2000 as
1900, or not at all. This inability to recognize or properly treat the
year 2000 may cause systems to process critical financial and operational
information incorrectly.
The Company continues to assess the impact of the Year 2000 issue on its
operations, including the development of final cost estimates for, and the
extent of programming changes required to address this issue. At this
time, the Company believes that the Year 2000 issue will not have a
material adverse effect on its financial condition, results of operations
or liquidity.
OUTLOOK
The Company's management and Board of Directors recognize that competition
will continue to increase in the future, especially in the energy supply
portion of our business. The introduction of competition into the markets,
coupled with the impact of the revised air quality standards on the
Company's operations, will result in numerous challenges and uncertainties
for Ameren and the utility industry. At this time, the Company cannot
predict the timing or impact of these matters on its future financial
condition, results of operations or liquidity.
ACCOUNTING MATTERS
In October 1996, the American Institute of Certified Public Accountants
issued Statement of Position 96-1, "Environmental Remediation Liabilities"
(SOP 96-1). This statement establishes standards for the recognition,
measurement, display and disclosure of environmental remediation
liabilities. In October 1997, the American Institute of Certified Public
Accountants issued Statement of Position 97-2, "Software Revenue
Recognition" (SOP 97-2). This statement establishes standards for
recognizing revenue on software transactions. SOP 96-1 is effective
January 1, 1997, and SOP 97-2 is effective for transactions entered into in
fiscal years beginning after December 15, 1997. SOP 96-1 and SOP 97-2 are
not expected to have a material effect on the Company's financial position
or results of operations upon adoption.
In February 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 128, "Earnings per Share" and
SFAS No. 129, "Disclosure of Information about Capital Structure". SFAS
128 establishes standards for computing and presenting earnings per share.
SFAS 129 establishes standards for disclosing information about an entity's
capital structure. In June 1997, the Financial Accounting Standards Board
issued SFAS No. 130, "Reporting Comprehensive Income" and SFAS No. 131,
"Disclosures about Segments of an Enterprise and Related Information".
SFAS 130 establishes standards for reporting and displaying of
comprehensive income. SFAS 131 establishes standards for reporting
information about operating segments in annual financial statements and
interim reports to shareholders. SFAS 128 and SFAS 129 are effective for
financial statements issued for periods ending after December 15, 1997.
SFAS 130 and SFAS 131 are effective for fiscal years beginning after
December 15, 1997. SFAS 128, SFAS 129, SFAS 130 and SFAS 131 are not
expected to have a material effect on the Company's financial position or
results of operations upon adoption.
EFFECTS OF INFLATION AND CHANGING PRICES
The Company's rates for retail electric and gas service are regulated by
the MoPSC and the ICC. Non-retail electric rates are regulated by the
FERC.
The current replacement cost of the Company's utility plant substantially
exceeds its recorded historical cost. Under existing regulatory practice,
only the historical cost of plant is recoverable from customers. As a
result, cash flows designed to provide recovery of historical costs through
depreciation may not be adequate to replace plant in future years.
However, existing regulatory practice may be modified for the Company's
generation portion of its business (see Note 2 - Regulatory Matters under
Notes to Supplemental Consolidated Financial Statements). In addition, the
impact on common stockholders is mitigated to the extent depreciable
property is financed with debt that is repaid with dollars of less
purchasing power.
In Illinois, changes in the cost of fuel for electric generation and gas
costs are generally reflected in billings to customers on a timely basis
through fuel and purchased gas adjustment clauses. However, existing
regulatory practice may be modified in Illinois for changes in the cost of
fuel for electric generation (see Note 2 - Regulatory Matters under Notes
to Supplemental Consolidated Financial Statements). In Missouri, the cost
of fuel for electric generation is reflected in base rates with no
provision for changes to be made through a fuel adjustment clause. Changes
in gas costs in Missouri are generally reflected in billings to customers
on a timely basis through purchased gas adjustment clauses. Inflation
continues to be a factor affecting operations, earnings, stockholders'
equity and financial performance.
SAFE HARBOR STATEMENT
Statements made in this report which are not based on historical facts are
forward-looking and, accordingly, involve risks and uncertainties that
could cause actual results to differ materially from those discussed.
Although such forward-looking statements have been made in good faith and
are based on reasonable assumptions, there is no assurance that the
expected results will be achieved. These statements include (without
limitation) statements as to future expectations, beliefs, plans,
strategies, objectives, legislation, events, conditions, financial
performance and dividends. In connection with the "Safe Harbor" provisions
of the Private Securities Litigation Reform Act of 1995, the Company is
providing the following cautionary statement to identify important factors
that could cause actual results to differ materially from those
anticipated. Factors include, but are not limited to, the effects of:
regulatory actions; changes in laws and other governmental actions;
competition; business and economic conditions; weather conditions; fuel
prices and availability; generation plant performance; monetary and fiscal
policies; and legal and administrative proceedings.
AMEREN CORPORATION
SUPPLEMENTAL CONSOLIDATED BALANCE SHEET
(Thousands of Dollars, Except Shares)
December 31, December 31,
ASSETS 1996 1995
Property and plant, at original
cost:
Electric $11,252,095 $10,991,058
Gas 428,531 403,349
Other 35,965 35,033
__________ __________
11,716,591 11,429,440
Less accumulated depreciation
and amortization 5,024,046 4,848,740
__________ __________
6,692,545 6,580,700
Construction work in progress:
Nuclear fuel in process 96,147 85,916
Other 162,414 199,600
__________ __________
Total property and plant, net 6,951,106 6,866,216
__________ __________
Investments and other assets:
Investments 113,310 105,081
Nuclear decommissioning trust fund 96,601 73,838
Other 64,655 55,983
__________ __________
Total investments and other
assets 274,566 234,902
__________ __________
Current assets:
Cash and cash equivalents 11,899 2,378
Accounts receivable - trade
(less allowance for doubtful
accounts of $5,795 and $7,525,
respectively) 268,839 256,309
Unbilled revenue 106,316 109,332
Other accounts and notes receivable 55,256 39,302
Materials and supplies, at average
cost -
Fossil fuel 106,153 107,366
Other 137,953 139,116
Other 42,759 42,023
__________ __________
Total current assets 729,175 695,826
__________ __________
Regulatory assets:
Deferred income taxes 734,206 777,613
Other 243,514 213,494
__________ __________
Total regulatory assets 977,720 991,107
__________ __________
Total Assets $ 8,932,567 $ 8,788,051
__________ __________
CAPITAL AND LIABILITIES
Capitalization:
Common stock, $.01 par value,
authorized 400,000,000 shares -
outstanding 137,215,462 shares $ 1,372 $ 1,372
Other paid-in capital, principally
premium on common stock 1,583,728 1,583,728
Retained earnings 1,431,295 1,385,629
__________ __________
Total common stockholders'
equity 3,016,395 2,970,729
Preferred stock not subject to
mandatory redemption (see
Note 4) 298,497 298,497
Preferred stock subject to
mandatory redemption (see
Note 4) 624 650
Long-term debt (see Note 6) 2,335,454 2,372,539
__________ __________
Total capitalization 5,650,970 5,642,415
__________ __________
Minority interest in consolidated
subsidiary 3,534 3,534
Current liabilities:
Current maturity of long-term debt 146,410 69,462
Short-term debt (see Note 5) 69,068 77,521
Accounts and wages payable 297,017 289,715
Accumulated deferred income taxes 43,933 27,429
Taxes accrued 65,245 58,988
Other 194,239 143,029
__________ __________
Total current liabilities 815,912 666,144
__________ __________
Accumulated deferred income taxes 1,653,095 1,677,146
Accumulated deferred investment tax
credits 209,227 218,758
Regulatory liability 304,172 329,708
Other deferred credits and
liabilities 295,657 250,346
__________ __________
Total Capital and Liabilities $ 8,932,567 $ 8,788,051
__________ __________
See Notes to Supplemental Consolidated Financial Statements
AMEREN CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars, Except Shares and Per Share Amounts)
December 31, December 31, December 31,
For the year ended 1996 1995 1994
OPERATING REVENUES:
Electric $ 3,066,940 $ 3,013,527 $ 3,035,512
Gas 254,412 217,420 224,527
Other 12,153 9,976 9,432
Total operating revenues 3,333,505 3,240,923 3,269,471
___________ ___________ ___________
OPERATING EXPENSES:
Operations
Fuel and purchased power 880,204 823,951 862,417
Gas costs 160,776 125,305 145,139
Other 543,998 542,386 535,590
___________ ___________ ___________
1,584,978 1,491,642 1,543,146
Maintenance 302,203 307,546 282,012
Depreciation and amortization 344,360 332,247 320,920
Income taxes 258,327 267,229 269,673
Other taxes 273,034 270,670 268,422
___________ ___________ ___________
Total operating expenses 2,762,902 2,669,334 2,684,173
OPERATING INCOME 570,603 571,589 585,298
OTHER INCOME AND DEDUCTIONS:
Allowance for equity funds
used during construction 6,870 7,716 6,397
Miscellaneous, net (15,907) (16,686) (5,515)
___________ ___________ ___________
Total other income and
deductions, net (9,037) (8,970) 882
INCOME BEFORE INTEREST CHARGES
AND PREFERRED DIVIDENDS 561,566 562,619 586,180
INTEREST CHARGES AND PREFERRED
DIVIDENDS:
Interest 180,402 178,826 183,761
Allowance for borrowed funds
used during construction (7,490) (6,179) (5,802)
Preferred dividends of
subsidiaries 16,970 17,100 16,762
___________ ___________ ___________
Net interest charges and
preferred dividends 189,882 189,747 194,721
NET INCOME $ 371,684 $ 372,872 $ 391,459
___________ ___________ ___________
EARNINGS PER SHARE OF COMMON
STOCK (BASED ON AVERAGE SHARES
OUTSTANDING) $2.71 $2.72 $2.85
___________ ___________ ___________
AVERAGE COMMON SHARES
OUTSTANDING 137,215,462 137,215,462 137,253,617
___________ ___________ ___________
See Notes to Supplemental Consolidated Financial Statements
AMEREN CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
December 31, December 31, December 31,
For the year ended 1996 1995 1994
Cash Flows From Operating:
Net income $ 371,684 $ 372,872 $ 391,459
Adjustments to reconcile
net income to net cash
provided by operating
activities:
Depreciation and
amortization 338,649 327,859 315,515
Amortization of
nuclear fuel 37,792 35,140 44,267
Allowance for funds
used during construction (14,360) (13,895) (12,199)
Postretirement
benefit accrued 11,923 24,680
Deferred income taxes,
net 12,665 4,003 1,021
Deferred investment
tax credits, net (9,531) (9,542) (9,549)
Changes in assets
and liabilities:
Receivables, net (25,468) (21,229) 13,494
Materials and
supplies 2,376 (174) (13,006)
Accounts and
wages payable 7,302 105,042 (104,378)
Taxes accrued 6,259 (7,085) 10,366
Other, net 58,732 (13,258) 46,384
___________ ___________ ___________
Net cash provided by
operating activities 786,100 791,656 708,054
Cash Flows From Investing:
Construction expenditures (435,904) (429,839) (455,965)
Allowance for funds used
during construction 14,360 13,895 12,199
Nuclear fuel expenditures (51,176) (42,444) (30,458)
Other (7,784) (10,047) (10,560)
___________ ___________ ___________
Net cash used in investing
activities (480,504) (468,435) (484,784)
Cash Flows From Financing:
Dividends on common
stock (326,855) (319,875) (312,460)
Environmental bond funds 4,443 12,583
Redemptions -
Nuclear fuel lease (34,819) (70,420) (32,137)
Short-term debt (18,300) (6,100) (84,100)
Long-term debt (35,000) (54,000) (45,000)
Common stock (1,020)
Preferred stock (26) (26) (26)
Issuances -
Nuclear fuel lease 43,884 49,134 51,386
Short-term debt 9,847 52,536 14,985
Long-term debt 65,194 19,766 170,000
___________ ___________ ___________
Net cash used in financing
activities (296,075) (324,542) (225,789)
Net change in cash and cash
equivalents 9,521 (1,321) (2,519)
Cash and cash equivalents
at beginning of year 2,378 3,699 6,218
___________ ___________ ___________
Cash and cash equivalents at
end of year $ 11,899 $ 2,378 $ 3,699
___________ ___________ ___________
Cash paid during the
periods:
Interest (net of amount
capitalized) $ 167,433 $ 173,569 $ 148,508
Income taxes $ 248,096 $ 274,820 $ 262,321
See Notes to Supplemental Consolidated Financial Statements
AMEREN CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENT OF RETAINED EARNINGS
(Thousands of Dollars)
Year Ended December 31, 1996 1995 1994
Balance at Beginning
of Period $1,385,629 $1,331,567 $1,254,920
Add:
Net income 371,684 372,872 391,459
Other 837 1,065
_________ _________ _________
1,758,150 1,705,504 1,646,379
_________ _________ _________
Deduct:
Common stock cash dividends 326,855 319,875 312,460
Other -- -- 2,352
_________ _________ _________
326,855 319,875 314,812
$1,431,295 $1,385,629 $1,331,567
Under mortgage indentures as amended, $34,435 of total retained earnings
was restricted against payment of common dividends - except those payable
in common stock, leaving $1,396,860 of free and unrestricted retained
earnings at December 31, 1996.
SELECTED QUARTERLY INFORMATION (Unaudited)
(Thousands of Dollars, Except Per Share Amounts)
Operating Operating Net Earnings Per
Revenues Revenues Income Common
Quarter Ended Share
March 31, 1996 $ 778,528 $106,393 $ 57,946 $ .42
March 31, 1995 731,621 100,938 47,479 .35
June 30, 1996 786,500 123,668 72,616 .53
June 30, 1995 777,269 141,629 85,608 .62
September 30, 1996 1,019,589 267,812 217,073 1.58
September 30, 1995 1,024,849 242,567 211,026 1.54
December 31, 1996 748,888 72,730 24,049 .18
December 31, 1995 707,184 86,455 28,759 .21
The first and second quarters of 1996 included credits to Missouri electric
customers which reduced net income approximately $8 million and $20
million, or 6 cents per share and 15 cents per share, respectively. In
addition, a 1.8% 1995 rate decrease for Missouri electric customers reduced
net income for the first, second and third quarters of 1996 by $4 million,
$5 million and $3 million, or 3 cents per share, 4 cents per share and 2
cents per share, respectively. Fourth quarter 1996 included Callaway Plant
refueling expenses which decreased net income approximately $18 million, or
13 cents per share. First quarter 1995 included expenses related to a
voluntary separation program which decreased net income by $4 million, or 3
cents per share. Second quarter 1995 included Callaway Plant refueling
expenses which decreased net income approximately $20 million, or 15 cents
per share. Third quarter 1995 reflected a one-time credit to Missouri
electric customers which reduced net income approximately $18 million, or
13 cents per share. In addition, the 1995 rate decrease reduced net income
$4 million, or 3 cents per share, in both third and fourth quarters of
1995. Also, in the third and fourth quarters of 1995, merger-related
expenses reduced net income approximately $9 million and $5 million, or 7
cents per share and 3 cents per share, respectively. Fourth quarter 1995
also included a write-off of system development costs which decreased net
income by $4 million, or 3 cents per share. Other changes in quarterly
earnings are due to the effect of weather on sales and other factors that
are characteristic of public utility operations.
See Notes to Supplemental Consolidated Financial Statements
AMEREN CORPORATION
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996
NOTE 1 - Summary of Significant Accounting Policies
Merger and Supplemental Financial Statements (Basis of Presentation)
Effective December 31, 1997, following the receipt of all required state and
federal regulatory approvals, Union Electric Company (AmerenUE) and CIPSCO
Incorporated (CIPSCO) combined to form Ameren Corporation (Ameren)(the
Merger). The accompanying supplemental consolidated financial statements
(the financial statements) reflect the accounting for the Merger as a
pooling of interests and are presented as if the companies were combined as
of the earliest period presented. However, the financial information is
not necessarily indicative of the results of operations, financial position
or cash flows that would have occurred had the Merger been consummated for
the periods for which it is given effect, nor is it necessarily indicative
of future results of operations, financial position, or cash flows. The
financial statements reflect the conversion of each outstanding share of
AmerenUE common stock into one share of Ameren common stock, and each
outstanding share of CIPSCO common stock into 1.03 shares of Ameren common
stock in accordance with the terms of the merger agreement. The
outstanding preferred stock of AmerenUE and Central Illinois Public Service
Company (AmerenCIPS), a subsidiary of CIPSCO, were not affected by the
Merger.
The accompanying financial statements include the accounts of Ameren and
its consolidated subsidiaries (collectively the Company). All subsidiaries
for which the Company owns directly or indirectly more than 50% of the
voting stock are included as consolidated subsidiaries. Ameren's primary
operating companies, AmerenUE and AmerenCIPS are engaged principally in the
generation, transmission, distribution and sale of electric energy and the
purchase, distribution, transportation and sale of natural gas in the
states of Missouri and Illinois. The Company also has a non-regulated
investing subsidiary, CIPSCO Investment Company (CIC). The Company has a
60% interest in Electric Energy, Inc. (EEI). EEI owns and operates an
electric generating and transmission facility in Illinois that supplies
electric power primarily to a uranium enrichment plant located in Paducah,
Kentucky.
All significant intercompany balances and transactions have been eliminated
from the consolidated financial statements.
Operating revenues and net income for each of the years in the three year
period ended December 31, 1996, were as follows (in millions):
AmerenUE CIPSCO OTHER AMEREN
Year ended December 31, 1996:
Operating revenues $2,260 $897 $177 $3,334
Net income 292 80 372
Year ended December 31, 1995:
Operating revenues $2,242 $842 $157 $3,241
Net income 301 72 373
Year ended December 31, 1994:
Operating revenues $2,224 $845 $200 $3,269
Net income 307 84 391
Regulation
Ameren will be a registered holding company and therefore subject to
regulation by the Securities and Exchange Commission (SEC) under the Public
Utility Holding Company Act of 1935 (PUHCA). AmerenUE and AmerenCIPS are
also regulated by the Missouri Public Service Commission (MoPSC), Illinois
Commerce Commission (ICC), and the Federal Energy Regulatory Commission
(FERC). The accounting policies of the Company are in accordance with the
ratemaking practices of the regulatory authorities having jurisdiction and,
as such, conform to Generally Accepted Accounting Principles (GAAP), as
applied to regulated public utilities.
Property and Plant
The cost of additions to and betterments of units of property and plant is
capitalized. Cost includes labor, material, applicable taxes, and
overheads, plus an allowance for funds used during construction.
Maintenance expenditures and the renewal of items not considered units of
property are charged to income as incurred. When units of depreciable
property are retired, the original cost and removal cost, less salvage, are
charged to accumulated depreciation.
Depreciation
Depreciation is provided over the estimated lives of the various classes of
depreciable property by applying composite rates on a straight-line basis.
The provision for depreciation in 1996, 1995 and 1994 was approximately 3%
of the average depreciable cost.
Fuel and Gas Costs
In Illinois, the Company adjusts fuel expense to recognize over- or under-
recoveries from customers of allowable fuel costs through the uniform fuel
adjustment clause (FAC). The FAC provides for the current recovery of
changes in the cost of fuel for electric generation in billings to
customers. The purchased gas adjustment clauses provide a matching of gas
costs with revenues in Illinois and in Missouri. The state of Missouri
does not have a FAC.
Nuclear Fuel
The cost of nuclear fuel is amortized to fuel expense on a unit-of-
production basis. Spent fuel disposal cost is charged to expense based on
kilowatthours sold.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments
purchased with a maturity of three months or less.
Income Taxes
The Company and its subsidiaries file a consolidated federal tax return.
Deferred tax assets and liabilities are recognized for the tax consequences
of transactions that have been treated differently for financial reporting
and tax return purposes, measured using statutory tax rates.
Investment tax credits utilized in prior years were deferred and are being
amortized over the useful lives of the related properties.
Allowance for Funds Used During Construction
Allowance for funds used during construction (AFC) is a utility industry
accounting practice whereby the cost of borrowed funds and the cost of
equity funds (preferred and common stockholders' equity) applicable to the
Company's construction program are capitalized as a cost of construction.
AFC does not represent a current source of cash funds. This accounting
practice offsets the effect on earnings of the cost of financing current
construction, and treats such financing costs in the same manner as
construction charges for labor and materials.
Under accepted rate-making practice, cash recovery of AFC, as well as other
construction costs, occurs when completed projects are placed in service
and reflected in customer rates. The AFC ranges of rates used during 1996,
1995 and 1994 were 7.7% - 9.0%, 9.0% - 9.3% and 8.9% - 9.0%, respectively.
Unamortized Debt Discount, Premium and Expense
Discount, premium and expense associated with long-term debt are amortized
over the lives of the related issues.
Revenue
The Company accrues an estimate of electric and gas revenues for service
rendered but unbilled at the end of each accounting period.
Stock Compensation Plans
The Company applies Accounting Principles Board Opinion No. 25, "Accounting
for Stock Issued to Employees" (APB 25) in accounting for its plans.
Long-Lived Assets
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of" became effective on January 1, 1996. SFAS 121 prescribes
general standards for the recognition and measurement of impairment losses.
SFAS 121 requires that regulatory assets which are no longer probable of
recovery through future revenues be charged to earnings (see Note 2 -
Regulatory Matters for further discussion). SFAS 121 did not have an
impact on the financial position, results of operations or liquidity of the
Company upon adoption.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires
management to make certain estimates and assumptions. Such estimates and
assumptions may affect reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses
during the reported period. Actual results could differ from those
estimates.
NOTE 2 - Regulatory Matters
In July 1995, the MoPSC approved an agreement involving the Company's
Missouri electric rates. The agreement decreased rates 1.8% for all
classes of Missouri retail electric customers, effective August 1, 1995,
reducing annual revenues by about $30 million and reducing annual earnings
by approximately 13 cents per share. In addition, a one-time $30 million
credit to retail Missouri electric customers reduced 1995 earnings
approximately 13 cents per share. Also included is a three-year
experimental alternative regulation plan that provides that earnings in any
future years in excess of a 12.61% regulatory return on equity (ROE) will
be shared equally between customers and stockholders, and earnings above a
14% ROE will be credited to customers. The formula for computing the
credit uses twelve-month results ending June 30, rather than calendar year
earnings. The agreement also provides that no party shall file for a
general increase or decrease in the Company's Missouri retail electric
rates prior to July 1, 1998, except that the Company may file for an
increase if certain adverse events occur. During 1996, the Company
recorded a $47 million credit for the first year of the plan, which reduced
earnings by $28 million, or 21 cents per share. This credit was reflected
as a reduction in electric revenues.
Included in the joint agreement approved by the MoPSC in its February 1997
order authorizing the Merger, is a new three-year experimental alternative
regulation plan that will run from July 1, 1998, through June 30, 2001.
Like the current plan, the new plan provides that earnings over a 12.61%
ROE up to a 14% ROE will be shared equally between customers and
shareholders. The new three-year plan will also return to customers 90% of
all earnings above a 14% ROE up to a 16% ROE. Earnings above a 16% ROE
would be credited entirely to customers. Other agreement provisions
include: recovery over a 10-year period of the Missouri portion of merger-
related expenses; a Missouri electric rate decrease, effective September 1,
1998, based on the weather-adjusted average annual credits to customers
under the current experimental alternative regulation plan; and an
experimental retail wheeling pilot program for 100 megawatts of electric
power. Also, as part of the agreement, the Company will not seek to
recover in Missouri the merger premium. The exclusion of the merger
premium from rates did not result in a charge to earnings.
In September 1997, the ICC approved the Merger subject to certain
conditions. The conditions included the requirement for AmerenUE and
AmerenCIPS to file electric and gas rate cases or alternative regulatory
plans within six months after the Merger is final to determine how net
merger savings would be shared between the ratepayers and stockholders.
In December 1997, the Governor of Illinois signed the Electric Service
Customer Choice and Rate Relief Law of 1997 (the Act) providing for utility
restructuring in Illinois. This legislation introduces price-based
competition into the supply of electric energy in Illinois and will provide
a less regulated structure for Illinois electric utilities. The Act
includes a 5 percent residential electric rate decrease for the Company's
Illinois electric customers, effective August 1, 1998. The Company may be
subject to additional 5 percent residential electric rate decreases in each
of 2000 and 2002 to the extent its rates exceed the Midwest utility average
at that time. The Company's rates are currently below the Midwest utility
average. The Company estimates that the initial 5 percent rate decrease
will result in a decrease in annual electric revenues of about $13 million,
based on estimated levels of sales and assuming normal weather conditions.
Retail direct access, which allows customers to choose their electric
generation supplier, will be phased in over several years. Access for
commercial and industrial customers will occur over a period from October
1999 to December 2000, and access for residential customers will occur
after May 1, 2002. The Act also relieves the Company of the requirement in
the ICC's Order issued in September 1997 (which approved the Merger),
requiring AmerenUE and AmerenCIPS to file electric rate cases or
alternative regulatory plans in Illinois following consummation of the
Merger to reflect the effects of net merger savings. Other provisions of
the Act include (1) potential recovery of a portion of a utility's stranded
costs through a transition charge collected from customers who choose
another electric supplier, (2) the option for certain utilities, including
the Company, to eliminate the retail FAC applicable to their rates and to
roll into base rates a historical level of fuel expense and (3) a mechanism
to securitize certain future revenues related to stranded costs.
The Company's accounting policies and financial statements conform to GAAP
applicable to rate-regulated enterprises and reflect the effects of the
ratemaking process in accordance with SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation". Such effects concern mainly the
time at which various items enter into the determination of net income in
order to follow the principle of matching costs and revenues. For example,
SFAS 71 allows the Company to record certain assets and liabilities
(regulatory assets and regulatory liabilities) which are expected to be
recovered or settled in future rates and would not be recorded under GAAP
for nonregulated entities. In addition, reporting under SFAS 71 allows
companies whose service obligations and prices are regulated to maintain
assets on their balance sheets representing costs they reasonably expect to
recover from customers, through inclusion of such costs in future rates.
SFAS 101, "Accounting for the Discontinuance of Application of FASB
Statement No. 71," specifies how an enterprise that ceases to meet the
criteria for application of SFAS 71 for all or part of its operations
should report that event in its financial statements. In general, SFAS 101
requires that the enterprise report the discontinuance of SFAS 71 by
eliminating from its balance sheet all regulatory assets and liabilities
related to the applicable portion of the business. At its July 24, 1997
meeting, the Emerging Issues Task Force of the Financial Accounting
Standards Board (EITF) concluded that application of SFAS 71 accounting
should be discontinued once sufficiently detailed deregulation legislation
is issued for a separable portion of a business for which a plan of
deregulation has been established. However, the EITF further concluded
that regulatory assets associated with the deregulated portion of the
business, which will be recovered through tariffs charged to customers of a
regulated portion of the business, should be associated with the regulated
portion of the business from which future cash recovery is expected (not
the portion of the business from which the costs originated), and can
therefore continue to be carried on the regulated entity's balance sheet to
the extent such assets are recovered. In addition, SFAS 121 establishes
accounting standards for the impairment of long lived assets (see Note 1 -
Summary of Significant Accounting Policies for further information).
Due to the enactment of the Act, prices for the supply of electric
generation are expected to transition from cost-based, regulated rates to
rates determined by competitive market forces in the state of Illinois. As
a result, the Company will discontinue application of SFAS 71 for the
Illinois portion of its generating business (i.e., the portion of the
Company's business related to the supply of electric energy in Illinois) in
the fourth quarter of 1997. At this time, the Company is assessing the
impact that the Act will have on its operations. The potential negative
consequences resulting from the Act could be significant and include the
impairment and writedown of certain assets, including generation-related
plant and regulatory assets, related to the Company's Illinois
jurisdictional assets. At September 30, 1997, the Company's net investment
in generation facilities related to its Illinois jurisdiction approximated
$826 million and was included in electric plant-in service on the Company's
balance sheet. In addition, at September 30, 1997, the Company's Illinois
generation-related net regulatory assets approximated $166 million. The
provisions of the Act could also result in lower revenues, reduced profit
margins and increased costs of capital. At this time, the Company is
unable to determine the impact of the Act on the Company's future financial
condition, results of operations or liquidity.
In the state of Missouri, where approximately 72 percent of the Company's
retail electric revenues are derived, a task force appointed by the MoPSC
is conducting studies of electric industry restructuring and competition
and will issue a report to the MoPSC in April 1998. A joint legislative
committee is also conducting studies and will report its findings and
recommendations to the Missouri General Assembly after reviewing the
results of the MoPSC task force.
The Company is unable to predict the timing or ultimate outcome of the
electric industry restructuring initiatives being considered in the state
of Missouri. In the state of Missouri, the potential negative consequences
of industry restructuring could be significant and include the impairment
and writedown of certain assets, including generation-related plant and
regulatory assets, lower revenues, reduced profit margins and increased
costs of capital. At September 30, 1997, the Company's net investment in
generation facilities related to its Missouri jurisdiction approximated
$2.7 billion and was included in electric plant-in service on the Company's
balance sheet. In addition, at September 30, 1997, the Company's Missouri
generation-related regulatory assets approximated $435 million. At this
time, the Company is unable to predict the impact of potential electric
industry restructuring matters in the state of Missouri on the Company's
future financial condition, results of operations or liquidity.
In April 1996, the FERC issued Order 888 and Order 889 related to the
industry's wholesale electric business. The Company filed an open access
tariff under Order 888 as part of the merger case and in July 1997, the
case was settled. In March 1997, the FERC issued Order 888A which required
the Company to refile a tariff by July 1997. The terms were not
significantly different from those filed in the original tariff under Order
888.
In accordance with SFAS 71, the Company has deferred certain costs pursuant
to actions of its regulators, and is currently recovering such costs in
electric rates charged to customers.
At December 31, the Company had recorded the following regulatory assets
and regulatory liability:
(in millions) 1996 1995
Regulatory Assets:
Income taxes $734 $778
Callaway costs 111 115
Undepreciated plant costs 41 --
Unamortized loss on reacquired debt 42 47
Contract termination costs 20 26
DOE decommissioning assessment 18 19
Other 12 6
___ ___
Regulatory Assets $978 $991
___ ___
Regulatory Liability:
Income taxes $304 $330
___ ___
Regulatory Liability $304 $330
___ ___
Income Taxes: See Note 7 - Income Taxes
Callaway Costs: Represents the Callaway Nuclear Plant operations and
maintenance expenses, property taxes and carrying costs incurred between
the plant in-service date and the date the plant was reflected in rates.
These costs are being amortized over the remaining life of the plant
(through 2024).
Undepreciated Plant Costs: Represents the unamortized cost of the Newton
Power Plant Unit 1 scrubber plus costs of removal. These costs are being
amortized over six years beginning in 1997.
Unamortized Loss on Reacquired Debt: Represents losses related to refunded
debt. These amounts are being amortized over the lives of the related new
debt issues or the remaining lives of the old debt issues if no new debt
was issued.
Contract Termination Costs: Represents costs incurred for terminating a
nuclear fuel purchase contract. These costs are being amortized over the
remaining life of the terminated contract (through 2001).
Department of Energy (DOE) Decommissioning Assessment: Represents fees
assessed by the DOE to decommission its uranium enrichment facility. These
costs are being amortized through 2007 as payments are made to the DOE.
The Company continually assesses the recoverability of its regulatory
assets. Under current accounting standards, regulatory assets are written
off to earnings when it is no longer probable that such amounts will be
recovered through future revenues. However, as noted in the above
paragraphs, electric industry restructuring legislation may impact the
recoverability of regulatory assets in the future.
NOTE 3 - Nuclear Fuel Lease
The Company has a lease agreement which provides for the financing of
nuclear fuel. At December 31, 1996, the maximum amount that could be
financed under the agreement was $120 million. Pursuant to the terms of
the lease, the Company has assigned to the lessor certain contracts for
purchase of nuclear fuel. The lessor obtains, through the issuance of
commercial paper or from direct loans under a committed revolving credit
agreement from commercial banks, the necessary funds to purchase the fuel
and make interest payments when due.
The Company is obligated to reimburse the lessor for all expenditures for
nuclear fuel, interest and related costs. Obligations under this lease
become due as the nuclear fuel is consumed at the Company's Callaway
Nuclear Plant. The Company reimbursed the lessor $37 million during 1996,
$34 million during 1995 and $34 million during 1994.
The Company has capitalized the cost, including certain interest costs, of
the leased nuclear fuel and has recorded the related lease obligation.
During the year 1996, 1995 and 1994, the total interest charges under the
lease were $6 million, $6 million and $5 million, respectively (based on
average interest rates of 5.7%, 6.1% and 4.7%, respectively) of which $3
million was capitalized in each respective year.
NOTE 4 - Preferred Stock of Subsidiaries
At December 31, 1996 and 1995, AmerenUE and AmerenCIPS had 25 million
shares and 4.6 million shares, respectively, of authorized preferred stock.
AmerenUE retired 260 shares, $6.30 Series preferred stock in each of the
years 1996, 1995, and 1994. On January 21, 1997, AmerenUE redeemed $64
million of preferred stock (see note (b) in table below).
Outstanding preferred stock is redeemable at the redemption prices shown
below:
December 31, 1996 1995
(in (in
millions) millions)
Preferred Stock Not Subject
to Mandatory Redemption:
Preferred stock outstanding without
par value (entitled to cumulative
dividends)
Redemption
Price
(per share)
Stated value of $100 per share--
$7.64 Series - 330,000 shares $103.82 - note (a) $33 $ 33
$7.44 Series - 330,001 shares 101.00 - note (b) 33 33
$6.40 Series - 300,000 shares 101.50 - note (b) 30 30
$5.50 Series A - 14,000 shares 110.00 1 1
$4.75 Series - 20,000 shares 102.176 2 2
$4.56 Series - 200,000 shares 102.47 20 20
$4.50 Series - 213,595 shares 110.00 - note (c) 21 21
$4.30 Series - 40,000 shares 105.00 4 4
$4.00 Series - 150,000 shares 105.625 15 15
$3.70 Series - 40,000 shares 104.75 4 4
$3.50 Series - 130,000 shares 110.00 13 13
4.00% Series - 150,000 shares 101.00 15 15
4.25% Series - 50,000 shares 102.00 5 5
4.90% Series - 75,000 shares 102.00 8 8
4.92% Series - 50,000 shares 103.50 5 5
5.16% Series - 50,000 shares 102.00 5 5
1993 Auction - 300,000 shares 100.00 30 30
note (d)
6.625% - 125,000 shares 100.00 - note (e) 13 13
Stated value of $25.00 per share--
$1.735 Series - 1,657,000 shares 25.00 - note (f) 41 41
___ ___
TOTAL PREFERRED STOCK NOT
SUBJECT TO MANDATORY REDEMPTION $298 $298
___ ___
Preferred Stock Subject to
Mandatory Redemption:
Preferred stock outstanding
without par value (entitled
to cumulative dividends)
Stated value of $100 per share--
$6.30 Series - 6,240 and 6,500
shares at respective dates,
due 2020 $100.00 - note (b) $1 $1
____ ____
TOTAL PREFERRED STOCK
SUBJECT TO MANDATORY REDEMPTION $1 $1
____ ____
(a) Beginning February 15, 2003, eventually declining to $100 per share.
(b) AmerenUE redeemed this series on January 21, 1997.
(c) In the event of voluntary liquidation, $105.50.
(d) Dividend rate for each dividend period (currently every 49 days) is
set at a then current market rate according to an auction procedure.
The rate at December 31, 1996 was 3.87%.
(e) Not redeemable prior to Octover 1, 1998.
(f) On or after August 1, 1998.
NOTE 5 - Short-Term Borrowings
Short-term borrowings of the Company consist of bank loans (maturities
generally on an overnight basis) and commercial paper (maturities generally
within 10-45 days). At December 31, 1996, $69 million of short-term
borrowings were outstanding. The weighted average interest rates on
borrowings outstanding at December 31, 1996 and 1995, were 7.2% and 6.0%,
respectively.
At December 31, 1996, the Company had committed bank lines of credit
aggregating $257 million (of which $246 million were unused) which make
available interim financing at various rates of interest based on LIBOR,
the bank certificate of deposit rate, or other options. These lines of
credit are renewable annually at various dates throughout the year.
NOTE 6 - Long-Term Debt of Subsidiaries
Long-term debt outstanding at December 31, was:
(in millions) 1996 1995
First Mortgage Bonds - note (a)
5 1/2% Series due 1997 $ 40 $ 40
6 3/4% Series due 1999 100 100
8.33% Series due 2002 75 75
7.65% Series due 2003 100 100
6 7/8% Series due 2004 188 188
7 3/8% Series due 2004 85 85
6 3/4% Series due 2008 148 148
7.40% Series due 2020 - note (b) 60 60
8 3/4% Series due 2021 125 125
8% Series due 2022 85 85
8 1/4% Series due 2022 104 104
7.15% Series due 2023 75 75
7% Series due 2024 100 100
5.45% Series due 2028 - note (b) 44 44
Series W 7 1/8% due 5/15/1999 50 50
Series X 6 1/8% due 7/01/1997 43 43
Series X 7 1/2% due 7/01/2007 50 50
Series Z 6 3/8% due 4/01/2003 40 40
Other 121 156
_____ _____
1,633 1,668
_____ _____
Missouri Environmental Improvement
Revenue bonds 1984 Series A due 2014 - note (c) 80 80
1984 Series B due 2014 - note (c) 80 80
1985 Series A due 2015 - note (d) 70 70
1985 Series B due 2015 - note (d) 57 57
1991 Series due 2020 - note (d) 43 43
1992 Series due 2022 - note (d) 47 47
_____ _____
377 377
_____ _____
Pollution Control Loan Obligations
1990 Series B 7.60% due 9/01/2013 32 32
1993 Series A 6 3/8% due 1/01/2028 35 35
1993 Series C-1 4.20% due 8/15/2026 - note (e) 35 35
Other 80 80
_____ _____
182 182
_____ _____
Subordinated Deferrable Interest Debentures
7.69% Series A due 2036 - note (f) 66 --
Unsecured Loans - notes (g) (h) -- --
Nuclear Fuel Lease 106 97
1991 Medium Term Notes 60 60
1994 Medium Term Notes 70 70
Unamortized Discount and (13) (12)
Premium on Debt
Maturities Due Within One Year (146) (69)
_____ _____
Total Long-Term Debt $2,335 $2,373
(a) At December 31, 1996, substantially all of the property and plant was
mortgaged under, and subject to liens of, the respective indentures
pursuant to which the bonds were issued.
(b) Environmental Improvement Series.
(c) On June 1 of each year, the interest rate is established for the
following year, or alternatively at the option of the Company, may be
fixed until maturity. A per annum rate of 3.65% is effective for the
year ended May 31, 1997. Thereafter, the interest rates will depend on
market conditions and the selection of an annual versus remaining life
rate by the Company. The average interest rate for the year ended
December 31, 1996, was 3.80%.
(d) Interest rates, and the periods during which such rates apply, vary
depending on the Company's selection of certain defined rate modes.
The average interest rates for the year 1996, for 1985 Series A, 1985
Series B, 1991 Series and 1992 Series bonds were 3.45%, 3.52%, 3.68%,
and 3.67%, respectively.
(e) Interest rates on the 1993 Series C-1 bonds will be adjusted to a then-
current market rate on August 15, 1998.
(f) During the terms of the debentures, the Company may, under certain
circumstances, defer the payment of interest for up to five years.
(g) A bank credit agreement due 1999 permits the Company to borrow up to
$200 million. Interest rates will vary depending on market conditions
and the Company's selection of various options under the agreement.
At December 31, 1996, no such borrowings were outstanding.
(h) A bank credit agreement due 1999 permits the Company to borrow or to
support commercial paper borrowings up to $300 million. Interest rates
will vary depending on market conditions. At December 31, 1996, no
such borrowings were outstanding.
Maturities of long-term debt through 2001 are as follows:
(in millions) Principal Amount
1997 $146
1998 43
1999 164
2000 39
2001 14
Amounts for years subsequent to 1998 do not include nuclear fuel lease
payments since the amounts of such payments are not currently determinable.
NOTE 7 - Income Taxes
Total income tax expense for 1996 resulted in an effective tax rate of 40%
on earnings before income taxes (40% in 1995 and 39% in 1994).
Principal reasons such rates differ from the statutory federal rate:
1996 1995 1994
Statutory federal income
tax rate 35% 35% 35%
Increases (Decreases) from:
Depreciation differences 1 1 1
State tax 4 4 4
Miscellaneous, net (1)
__ __ __
Effective income tax rate 40% 40% 39%
Income tax expense components:
(in millions) 1996 1995 1994
Taxes currently payable
(principally federal):
Included in operating expenses $261 $273 $281
Included in other income--
Miscellaneous, net (6) (7) (9)
___ ___ ___
255 266 272
Deferred taxes
(principally federal):
Included in operating expenses--
Depreciation differences 2 10 6
Postretirement benefits (9) (10)
Other 5 2 2
Included in other income--
Depreciation differences 1 1 1
Other 1
___ ___ ___
8 4 --
Deferred investment tax
credits, amortization
Included in operating expenses (9) (9) (9)
___ ___ ___
Total income tax expense $254 $261 $263
___ ___ ___
In accordance with SFAS 109, "Accounting for Income Taxes," a regulatory
asset, representing the probable recovery from customers of future income
taxes which is expected to occur when temporary differences reverse, was
recorded along with a corresponding deferred tax liability. Also, a
regulatory liability, recognizing the lower expected revenue resulting from
reduced income taxes associated with amortizing accumulated deferred
investment tax credits, was recorded. Investment tax credits have been
deferred and will continue to be credited to income over the lives of the
related property.
The Company adjusts its deferred tax liabilities for changes enacted in tax
laws or rates. Recognizing that regulators will probably reduce future
revenues for deferred tax liabilities initially recorded at rates in excess
of the current statutory rate, reductions in the deferred tax liability
were credited to the regulatory liability.
Temporary differences gave rise to the following deferred tax assets and
deferred tax liabilities at December 31:
(in millions) 1996 1995
Accumulated Deferred Income Taxes:
Depreciation $1,070 $1,060
Regulatory assets, net 488 516
Capitalized taxes and expenses 199 210
Deferred benefit costs (48) (52)
Disallowed plant costs (14) (13)
Regulatory liabilities, net (46) (54)
Leveraged leases 35 31
Other 13 7
_____ _____
Total net accumulated deferred
income tax liabilities $1,697 $1,705
NOTE 8 - Retirement Benefits
The Company has defined-benefit retirement plans covering substantially all
of its employees. Benefits are based on the employees' years of service
and compensation. The Company's plans are funded in compliance with income
tax regulations and federal funding requirements.
Pension costs for the years 1996, 1995 and 1994, were $32 million, $32
million and $36 million, respectively.
Following is the pension plan information related to AmerenUE plans as of
December 31:
Funded Status of Pension Plans
(in millions) 1996 1995 1994
Actuarial present value of benefit
obligation:
Vested benefit obligation $661 $679 $552
___ ___ ___
Accumulated benefit obligation $752 $758 $622
___ ___ ___
Projected benefit obligation for
service rendered to date $919 $913 $779
Plan assets at fair value * 924 847 706
___ ___ ___
(Excess) Deficiency of plan assets
versus projected benefit obligation (5) 66 73
Unrecognized net gain 96 22 18
Unrecognized prior service cost (76) (82) (89)
Unrecognized net assets at transition 8 9 10
___ ___ ___
Accrued pension cost at December 31 $ 23 $ 15 $ 12
___ ___ ___
* Plan assets consist principally of common stocks and fixed income
securities.
Components of Net Pension Expense
(in millions) 1996 1995 1994
Service cost - benefits earned
during the period $ 22 $ 19 $ 21
Interest cost on projected
benefit obligation 65 66 60
Actual return on plan assets (107) (166) 8
Net amortization and deferral 48 107 (58)
___ ___ ___
Pension Cost $ 28 $ 26 $ 31
___ ___ ___
Assumptions for Actuarial Present Value of Projected Benefit Obligations:
1996 1995 1994
Discount rate at measurement date 7.5% 7.25% 8.5%
Increase in future compensation 4.5% 4.25% 5.5%
Plan assets long-term rate of return 8.5% 8.5% 8.5%
____ ____ ____
AmerenCIPS uses a September 30 measurement date for its valuation of
pension plan assets and liabilities. Following is the pension plan
information related to AmerenCIPS plans as of December 31:
Funded Status of Pension Plans
(in millions) 1996 1995 1994
Actuarial present value of benefit
obligation:
Vested benefit obligation $148 $121 $120
___ ___ ___
Accumulated benefit obligation $171 $142 $124
___ ___ ___
Projected benefit obligation for
service rendered to date $211 $181 $163
Plan assets at fair value * 253 221 188
___ ___ ___
(Excess) Deficiency of plan assets
versus projected benefit obligation (42) (40) (25)
Unrecognized net gain 40 33 23
Unrecognized prior service cost (11) (5) (6)
Unrecognized net assets at transition 3 4 4
Prepaid pension costs at September 30 (10) (8) (4)
Expense, net of funding October to
December (1) -- --
___ ___ ___
Prepaid pension cost at December 31 $(11) $ (8) $ (4)
___ ___ ___
* Plan assets consist principally of common and preferred stocks, bonds,
money market instruments and real estate.
Components of Net Pension Expense
(in millions) 1996 1995 1994
Service cost - benefits earned
during the period $ 7 $ 7 $ 8
Interest cost on projected
benefit obligation 13 12 11
Actual return on plan assets (30) (34) (7)
Net amortization and deferral 14 21 (7)
___ ___ ___
Pension Cost $ 4 $ 6 $ 5
___ ___ ___
Assumptions for Actuarial Present Value of Projected Benefit Obligations
1996 1995 1994
Discount rate at measurement date 7.5% 7.5% 7.75%
Increase in future compensation 4.5% 4.5% 4.8%
Plan assets long-term rate of return 8.5% 8.0% 8.0%
____ ____ ____
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees.
Substantially all of the Company's employees may become eligible for those
benefits if they reach retirement age while working for the Company. The
Company accrues the expected postretirement benefit costs during employees'
years of service.
The following is information related to AmerenUE postretirement benefit
plans as of December 31:
AmerenUE's funding policy is to contribute to a Voluntary Employee
Beneficiary Association trust (VEBA) annually the net periodic cost.
Postretirement benefit costs were $44 million for each of the years 1996
and 1995 and $46 million for 1994, of which approximately 19% was charged
to construction accounts in each of the three years. AmerenUE's transition
obligation at December 31, 1996, is being amortized over the next 16 years.
In August 1994, the MoPSC authorized the recovery of postretirement benefit
costs in rates to the extent that such costs are funded. In December 1995,
the Company established two external trust funds for retiree healthcare and
life insurance benefits. For both 1995 and 1994, actual claims paid were
approximately $15 million. In 1996, claims were paid out of the plan trust
funds.
Funded Status of the Plans
(in millions) 1996 1995 1994
Accumulated postretirement
benefit obligation
Active employees eligible for
benefits $ 38 $ 74 $ 42
Retired employees 193 211 188
Other active employees 80 32 60
___ ___ ___
Total benefit obligation 311 317 290
Plan assets at fair market value* 47 14 --
___ ___ ___
Accumulated postretirement
benefit obligation in excess of
plan assets 264 303 290
Unrecognized - transition obligation (200) (213) (225)
- gain/(loss) 19 (7) 4
___ ___ ___
Postretirement benefit liability at
December 31 $ 83 $ 83 $ 69
___ ___ ___
* Plan assets consist principally of common stocks and fixed income
securities.
Components of Postretirement Benefit Cost
(in millions) 1996 1995 1994
Service cost - benefits earned
during the period $ 12 $ 10 $ 11
Interest cost on projected
benefit obligation 22 24 21
Actual return on plan assets (4) -- --
Amortization - transition obligation 12 12 13
- unrecognized
(gain)/loss (1) (2) 1
Deferred gain 3 -- --
___ ___ ___
Net periodic cost $ 44 $ 44 $ 46
___ ___ ___
Assumptions for the Obligation Measurements
1996 1995 1994
Discount rate at measurement date 7.5% 7.25% 8.5%
Plan assets long-term rate of return 8.5% 8.5% --
Medical cost trend rate - initial 8.25% 9.25% 11.0%
- ultimate 5.25% 5.25% 6.0%
____ ____ ____
Ultimate medical cost trend rate
expected in year 2000 2000 2000
____ ____ ____
A 1% increase in the medical cost trend rate is estimated to increase the
net periodic cost and the accumulated postretirement benefit obligation by
approximately $3 million and $23 million, respectively.
The following is information related to AmerenCIPS postretirement benefit
plans as of December 31:
AmerenCIPS' funding policy is to fund the two VEBAs and the 401(h) account
established within the AmerenCIPS retirement income trust with no more than
the actual annual postretirement medical benefit obligation as determined
by actuarial calculation and no less than the revenue provided in
AmerenCIPS' utility rate structure for the obligation. AmerenCIPS uses a
September 30 measurement date for its valuation of postretirement assets
and liabilities.
Postretirement benefit costs were $16 million for 1996 and $17 million for
each of the years 1995 and 1994, of which approximately 15% was charged to
construction accounts in each of the three years. AmerenCIPS' transition
obligation at December 31, 1996, is being amortized over 20 years.
Funded Status of the Plans
(in millions) 1996 1995 1994
Accumulated postretirement benefit
obligation
Active employees eligible for benefits $ 20 $ 17 $ 15
Retired employees 54 50 48
Other active employees 65 76 64
___ ___ ___
Total benefit obligation 139 143 127
Plan assets at fair market value* 71 49 27
___ ___ ___
Accumulated postretirement
benefit obligation in excess of
plan assets 68 94 100
Unrecognized - transition obligation (89) (99) (104)
- gain/(loss) 38 24 21
--- --- ---
Accrued postretirement benefit cost
at September 30 17 19 17
Expense, net of funding, October to
December (14) (15) (15)
___ ___ ___
Postretirement benefit liability at
December 31 $ 3 $ 4 $ 2
___ ___ ___
* Plan assets consist principally of common and preferred stocks, bonds,
money market instruments and real estate.
Components of Postretirement Benefit Cost
(in millions) 1996 1995 1994
Service cost - benefits earned
during the period $ 4 $ 4 $ 4
Interest cost on projected
benefit obligation 11 10 9
Actual return on plan assets (9) (8) --
Amortization of transition obligation 6 6 6
Deferred gains (losses) 4 5 (2)
___ ___ ___
Net periodic cost $ 16 $ 17 $ 17
___ ___ ___
Assumptions for the Obligation Measurements
1996 1995 1994
Discount rate at measurement date 7.5% 7.5% 8.25%
Plan assets long-term rate of return 8.5% 8.0% 8.0%
Medical cost trend rate - initial 9.8% 10.6% 11.4%
- ultimate 4.5% 4.0% 4.0%
Ultimate medical cost trend rate
expected in year 2005 2007 2007
____ ____ ____
A 1% increase in the medical cost trend rate is estimated to increase the
net periodic cost and the accumulated postretirement benefit obligation as
of September 30, 1996 by approximately $3 million and $23 million,
respectively.
NOTE 9 - Stock Option Plans
AmerenUE has a long-term incentive plan (the Plan) for eligible employees.
The Plan provides for the grant of options, performance awards, restricted
stock, dividend equivalents and stock appreciation rights. Under the terms
of the Plan, options may be granted at a price not less than the fair
market value of the common shares at the date of grant. Granted options
vest over a period of five years, beginning at the date of grant, and
provide for acceleration of exercisability of the options upon the
occurrence of certain events, including retirement. Outstanding options
expire on various dates through 2006. Under the Plan, subject to
adjustment as provided in the Plan, 2.5 million shares have been authorized
to be issued or delivered. As of merger effective date, AmerenUE shares
under the Plan were converted to Ameren shares.
Summary of stock options:
1995
Options outstanding at beginning of the year --
Options granted during the year 142,500
Options exercised during the year --
Options expired/canceled during the year --
Options outstanding at end of the year 142,500
Options exercisable at end of the year 9,800
_______
Exercise price range of options granted $35 1/2 - $35 7/8
_________________
1996
Options outstanding at beginning of the year 142,500
Options granted during the year 165,590
Options exercised during the year --
Options expired/canceled during the year 700
Options outstanding at end of the year 307,390
Options exercisable at end of the year 39,710
_______
Exercise price of options granted $43
_______
In accordance with APB 25, no compensation cost has been recognized for the
Company's stock compensation plans. In 1996, the Company adopted the
disclosure-only method under SFAS 123, "Accounting for Stock-Based
Compensation." If the fair value based accounting method under this
statement had been used to account for stock-based compensation cost, the
effects on 1996 and 1995 net income and earnings per share would have been
immaterial.
NOTE 10 - Commitments and Contingencies
The Company is engaged in a construction program under which expenditures
averaging approximately $340 million, including AFC, are anticipated during
each of the next five years. This estimate does not include any
construction expenditures which may be incurred by the Company to meet new
air quality standards for ozone and particulate matter, as discussed later
in this Note.
AmerenUE has commitments for the purchase of coal under long-term
contracts. Coal contract commitments, including transportation costs, for
1997 through 2001 are estimated to total $789 million (excluding contract
escalation provisions). Total coal purchases, including transportation
costs, for 1996, 1995 and 1994 were $270 million, $293 million and $268
million, respectively. AmerenUE also has existing contracts with pipeline
and natural gas suppliers to provide natural gas for distribution and
electric generation. Gas-related contracted cost commitments for 1997
through 2001 are estimated to total $99 million. Total delivered natural
gas costs for 1996, 1995 and 1994 were $64 million, $60 million and $63
million, respectively. AmerenUE's nuclear fuel commitments for 1997
through 2001, including uranium concentrates, conversion, enrichment and
fabrication, are expected to total $151 million, and are expected to be
financed under the nuclear fuel lease. Nuclear fuel expenditures for 1996,
1995 and 1994 were $51 million, $42 million, and $30 million, respectively.
Additionally, AmerenUE has long-term contracts with other utilities to
purchase electric capacity. These commitments for 1997 through 2001 are
estimated to total $201 million. During 1996, 1995 and 1994, electric
capacity purchases were $44 million, $42 million and $38 million,
respectively.
AmerenCIPS also has commitments for the purchase of coal under long-term
contracts. Total coal commitments, including transportation costs, for
1997 through 2001 are estimated to total $788 million (excluding contract
escalation provisions). Total coal purchases for AmerenCIPS, including
transportation costs, for 1996, 1995 and 1994 were $217 million, $189
million, and $193 million, respectively. AmerenCIPS also has existing
contracts with pipeline and natural gas suppliers to provide natural gas
for distribution. Gas-related contract commitments for 1997 through 2001
are estimated at $148 million. Total delivered natural gas costs for 1996,
1995 and 1994 were $97 million, $67 million and $85 million, respectively.
During 1996, AmerenCIPS restructured its contract with one of its major
coal suppliers. In 1997, AmerenCIPS paid a $70 million restructuring
payment to the supplier, which allows them to purchase at market prices low-
sulfur, out-of-state coal through the 30 supplier (in substitution for the
high-sulfur Illinois coal AmerenCIPS was obligated to purchase under the
original contract); and would receive options for future purchases of
low-sulfur, out-of-state coal from the supplier through 1999 at set
negotiated prices.
By switching to low-sulfur coal, AmerenCIPS was able to discontinue
operating the Newton Power Plant Unit 1 scrubber. The benefits of the
restructuring include lower cost coal, avoidance of significant capital
expenditures to renovate the scrubber, and elimination of scrubber
operating and maintenance costs (offset by scrubber retirement expenses).
The net benefits of restructuring are expected to exceed $100 million over
the next 10 years. In December 1996, the ICC entered an order approving
the switch to out-of-state coal, recovery of the restructuring payment plus
associated carrying costs (Restructuring Charges) through the retail FAC
over six years, and continued recovery in rates of the undepreciated
scrubber investment plus costs of removal. A group of industrial customers
filed with the Illinois Third District Appellate Court (the Court) in
February 1997 an appeal of the December 1996 order of the ICC which
approved, among other things, recovery of the Restructuring Charges through
the retail FAC. Additionally, in May 1997 the FERC approved recovery of
the wholesale portion of the Restructuring Charges through the wholesale
FAC.
As a result of the ICC and FERC orders, AmerenCIPS classified the $72
million of the Restructuring Charges made to the coal supplier in February
1997 as a regulatory asset and, through October 1997, recovered
approximately $9.5 million of the Restructuring Charges through the retail
FAC and from wholesale customers.
On November 24, 1997, the Court reversed the ICC's order, finding that the
Restructuring Charges were not direct costs of fuel that may be recovered
through the retail FAC, but rather should be considered as a part of a
review of AmerenCIPS' aggregate revenue requirements in a full rate case.
Restructuring Charges allocated to wholesale customers (approximately 16
percent of the total) are not in question as a result of the opinion of the
Court. On December 8, 1997, AmerenCIPS requested a rehearing by the Court.
The Company is evaluating the impact of the Court decision on its financial
statements. The Company cannot predict the ultimate outcome of this
matter. If the Court's decision should ultimately prevail, AmerenCIPS will
be required to cease recovery of the Restructuring Charges through the
retail FAC, and could be required to refund any portion of those charges
that had been collected through the retail FAC. The Company is also
exploring other alternatives for recovery of the Restructuring Charges.
The Company is currently evaluating the unamortized retail portion of the
Restructuring Charges, which is currently classified as a regulatory asset,
to determine if it continues to meet the criteria for the existence of an
asset under GAAP. If it is determined that such criteria are not met, the
unamortized balance of the Restructuring Charges, approximately $36
million, net of tax, could be charged to earnings. The Company is also
evaluating the revenues previously recovered in 1997 through the retail FAC
to determine if a loss contingency, as defined under GAAP, is required.
Such loss contingency ($5 million, net of tax) could also be charged to
earnings.
The Company's insurance coverage for its Callaway Nuclear Plant at December
31, 1996 was as follows:
Type and Source of Coverage
(in millions) Maximum Maximum
Coverages Assessments
for Single
Incidents
Public Liability:
American Nuclear Insurers $ 200 $ --
Pool Participation 8,720 79 (a)
______ ______
$ 8,920 (b) $ 79
______ ______
Nuclear Worker Liability:
American Nuclear Insurers $ 200 (c) $ 3
Property Damage:
American Nuclear Insurers $ 500 $ --
Nuclear Electric Insurance Ltd. 2,250 (d) 13
______ ______
$ 2,750 $ 13
______ ______
Replacement Power:
Nuclear Electric Insurance Lt. $ 419 (e) $ 3
(a) Retrospective premium under the Price-Anderson liability provisions of
the Atomic Energy Act of 1954, as amended, (Price-Anderson). Subject to
retrospective assessment with respect to loss from an incident at any U.S.
reactor, payable at $10 million per year.
(b) Limit of liability for each incident under Price-Anderson.
(c) Total industry potential liability from workers claiming exposure to
the hazard of nuclear radiation. The policy includes an automatic
reinstatement thereby providing total coverage of $400 million.
(d) Includes premature decommissioning costs.
(e) Weekly indemnity of $3 million, for 52 weeks which commences after the
first 21 weeks of an outage, plus $3 million per week for 104 weeks
thereafter.
Price-Anderson limits the liability for claims from an incident involving
any licensed U.S. nuclear facility. The limit is based on the number of
licensed reactors and is adjusted at least every five years based on the
Consumer Price Index. Utilities owning a nuclear reactor cover this
exposure through a combination of private insurance and mandatory
participation in a financial protection pool as established by Price-
Anderson.
If losses from a nuclear incident at the Callaway Plant exceed the limits
of, or are not subject to, insurance, or if coverage is not available, the
Company will self-insure the risk. Although the Company has no reason to
anticipate a serious nuclear incident, if one did occur it could have a
material but indeterminable adverse effect on the Company's financial
position, results of operations or liquidity.
Under the Clean Air Act Amendments of 1990, the Company is required to
reduce total annual sulfur dioxide emissions significantly by the year
2000. Significant reductions in nitrogen oxide are also required. By
switching to low-sulfur coal and early banking of emission credits, the
Company anticipates that it can comply with the requirements of the law
without significant revenue increases because the related capital costs are
largely offset by lower fuel costs. As of year-end 1996, estimated
remaining capital costs expected to be incurred pertaining to Clean Air Act-
related projects totaled $76 million.
In July 1997, the United States Environmental Protection Agency (EPA)
issued final regulations revising the National Ambient Air Quality
Standards for ozone and particulate matter. Although specific emission
control requirements are still being developed, it is believed that the
revised standards will require significant additional reductions in
nitrogen oxide and sulfur dioxide emissions from coal-fired boilers. In
October 1997, the EPA announced that Missouri and Illinois are included in
the area targeted for nitrogen oxide emissions reductions as part of their
regional control program. Reduction requirements in nitrogen oxide
emissions from the Company's coal-fired boilers could exceed 80 percent
from 1990 levels by the year 2002. Reduction requirements in sulfur
dioxide emissions may be up to 50 percent beyond that already required by
Phase II acid rain control provisions of the 1990 Clean Air Act Amendments
and are anticipated to be required by 2007. Because of the magnitude of
these additional reductions, the Company could be required to incur
significantly higher capital costs to meet future compliance obligations
for its coal-fired boilers or purchase power from other sources, either of
which could have significantly higher operating and maintenance
expenditures associated with compliance. At this time the Company is
unable to determine the impact of the revised air quality standards on the
Company's future financial condition, results of operations or liquidity.
The United States and other countries are discussing possibilities for an
international treaty to address the issue of "global warming." The Company
is unable to predict what agreements, if any, will be adopted. However,
most of the proposals under discussion could result in significantly higher
capital costs and operations and maintenance expenditures by the Company.
At this time, the Company is unable to determine the impact of these
proposals on the Company's future financial condition, results of
operations or liquidity.
As of December 31, 1996, AmerenUE was designated a potentially responsible
party (PRP) by federal and state environmental protection agencies at four
hazardous waste sites. Other hazardous waste sites have been identified
for which AmerenUE may be responsible but has not been designated a PRP.
AmerenCIPS has identified 13 sites where it and certain of its predecessors
and other affiliates previously operated facilities that manufactured gas
from coal. This manufacturing produced various potentially harmful by-
products which may remain on some sites. One site was added to the EPA
Superfund list in 1990.
Costs relating to studies and remediation at the 13 AmerenCIPS' sites and
associated legal and litigation expenses are being accrued and deferred
rather than expensed currently, pending recovery through rates or from
insurers. Through December 31, 1996, the total of the costs deferred, net
of recoveries from insurers and through environmental adjustment clause
rate riders approved by the ICC, was $11 million.
The ICC has instituted a reconciliation proceeding to review AmerenCIPS'
environmental remediation activities in 1993, 1994 and 1995 and to
determine whether the revenues collected under the riders in 1993 were
consistent with the amount of remediation costs prudently and properly
incurred. Amounts found to have been incorrectly included under the riders
would be subject to refund. In mid-1997, AmerenCIPS and the ICC Staff
submitted a stipulation with regard to all matters at issue. Under the
stipulation, as of December 31, 1995, the aggregate amount of (i) revenues
received under the riders, insurance proceeds (and related interest)
exceeded (ii) rider-related costs (and related carrying costs) by
approximately $4 million. If this stipulation is approved by the ICC, this
amount would be applied to cover a portion of future remediation costs.
Also, if the stipulation is approved, insurance proceeds of approximately
$3 million would be applied to cover non-rider related costs incurred.
During 1997, the accumulated balance of recoverable environmental
remediation costs exceeded the balance of available insurance proceeds and
rider revenues; therefore, AmerenCIPS began to again collect revenue under
the riders beginning November 1, 1997.
The Company continually reviews remediation costs that may be required for
all of these sites. Any unrecovered environmental costs are not expected
to have a material adverse effect on the Company's financial position,
results of operations or liquidity.
The International Union of Operating Engineers Local 148 and the
International Brotherhood of Electrical Workers Local 702 filed unfair
labor practice charges with the National Labor Relations Board (NLRB)
relating to the legality of the lockout by AmerenCIPS of both unions during
1993. The NLRB has issued complaints against AmerenCIPS concerning its
lockout. Both unions seek, among other things, back pay and other benefits
for the period of the lockout. The Company estimates the amount of back
pay and other benefits for both unions to be less than $17 million. An
administrative law judge of the NLRB has ruled that the lockout was
unlawful. On July 23, 1996, the Company appealed to the NLRB. The Company
believes the lockout was both lawful and reasonable and that the final
resolution of the disputes will not have a material adverse effect on
financial position, results of operations or liquidity of the Company.
Regulatory changes enacted and being considered at the federal and state
levels continue to change the structure of the utility industry and utility
regulation, as well as encourage increased competition. At this time, the
Company is unable to predict the impact of these changes on the Company's
future financial condition, results of operations or liquidity. See Note 2
- - Regulatory Matters for further discussion.
The Company is involved in other legal and administrative proceedings
before various courts and agencies with respect to matters arising in the
ordinary course of business, some of which involve substantial amounts.
The Company believes that the final disposition of these proceedings will
not have a material adverse effect on its financial position, results of
operations or liquidity.
NOTE 11 - Callaway Nuclear Plant
Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the
permanent storage and disposal of spent nuclear fuel. DOE currently
charges one mill per nuclear generated kilowatthour sold for future
disposal of spent fuel. Electric rates charged to customers provide for
recovery of such costs. DOE is not expected to have its permanent storage
facility for spent fuel available until at least 2015. The Company has
sufficient storage capacity at the Callaway Plant site until 2005 and has
viable storage alternatives under consideration. Each alternative will
likely require Nuclear Regulatory Commission approval and may require other
regulatory approvals. The delayed availability of DOE's disposal facility
is not expected to adversely affect the continued operation of Callaway
Plant.
Electric rates charged to customers provide for recovery of Callaway Plant
decommissioning costs over the life of the plant, based on an assumed 40-
year life, ending with expiration of the plant's operating license in 2024.
The Callaway site is assumed to be decommissioned using the DECON
(immediate dismantlement) method. Decommissioning costs, including
decontamination, dismantling and site restoration, are estimated to be $451
million in current year dollars and are expected to escalate approximately
4% per year through the end of decommissioning activity in 2033.
Decommissioning cost is charged to depreciation expense over Callaway's
service life and amounted to $7 million in each of the years 1996, 1995 and
1994. Every three years, the MoPSC requires the Company to file updated
cost studies for decommissioning Callaway, and electric rates may be
adjusted at such times to reflect changed estimates. The latest study was
performed in 1996. Costs collected from customers are deposited in an
external trust fund to provide for Callaway's decommissioning. Fund
earnings are expected to average 9.25% annually through the date of
decommissioning. If the assumed return on trust assets is not earned, the
Company believes it is probable that such earnings deficiency will be
recovered in rates. Trust fund earnings, net of expenses, appear on the
balance sheet as increases in nuclear decommissioning trust fund and in the
accumulated provision for nuclear decommissioning.
The staff of the SEC has questioned certain of the current accounting
practices of the electric utility industry, regarding the recognition,
measurement and classification of decommissioning costs for nuclear
generating stations in the financial statements of electric utilities. In
response to these questions, the Financial Accounting Standards Board has
agreed to review the accounting for removal costs, including
decommissioning. The Company does not expect that changes in the
accounting for nuclear decommissioning costs will have a material effect on
its financial position, results of operations or liquidity.
NOTE 12 - Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to
estimate that value.
Cash and Temporary Investments/Short-Term Borrowings
The carrying amounts approximate fair value because of the short-term
maturity of these instruments.
Marketable Securities
The fair value is based on quoted market prices obtained from dealers or
investment managers.
Financial Derivatives
The fair value is estimated using market values of options, calls and
futures contracts on organized exchanges.
Nuclear Decommissioning Trust Fund
The fair value of the Company's nuclear decommissioning trust fund is
estimated based on quoted market prices for securities.
Preferred Stock of Subsidiaries
The fair value is estimated based on the quoted market prices for the same
or similar issues.
Long-Term Debt of Subsidiaries
The fair value is estimated based on the quoted market prices for same or
similar issues or on the current rates offered to the Company for debt of
comparable maturities.
Carrying amounts and estimated fair values of the Company's financial
instruments at December 31:
1996 1995
------------------ ------------------
(in millions) Carrying Fair Carrying Fair
Amount Value Amount Value
Marketable securities $ 51 $ 51 $ 46 $ 46
Preferred stock 299 257 299 254
Long-term debt (including
current portion) 2,482 2,545 2,442 2,583
_____ _____ _____ _____
The Company has investments in debt and equity securities that are held in
trust funds for the purpose of funding the nuclear decommissioning of the
Callaway Nuclear Plant (see Note 11 - Callaway Nuclear Plant). The Company
has classified these investments in debt and equity securities as available
for sale and has recorded all such investments at their fair market value
at December 31, 1996 and 1995. In 1996, 1995 and 1994, the proceeds from
the sale of investments were $20 million, $9 million and $22 million,
respectively. Using the specific identification method to determine cost,
the gross realized gains on those sales were approximately $1 million each
for 1996, 1995, and 1994. Net realized and unrealized gains and losses are
reflected in accumulated provision for nuclear decommissioning on the
Balance Sheet, which is consistent with the method used by the Company to
account for the decommissioning costs recovered in rates.
Costs and fair values of investments in debt and equity securities in the
nuclear decommissioning trust fund at December 31 were as follows:
1996 (in millions) Gross Unrealized
Security Type Cost Gain (Loss) Fair Value
Debt Securities $29 $ 2 $-- $31
Equity Securities 40 22 -- 62
Cash equivalents 4 -- -- 4
__ __ __ __
$73 $24 $-- $97
__ __ __ __
1995 (in millions) Gross Unrealized
Security Type Cost Gain (Loss) Fair Value
Debt Securities $22 $ 3 $-- $25
Equity Securities 38 9 -- 47
Cash equivalents 2 -- -- 2
__ __ __ __
$62 $12 $-- $74
__ __ __ __
The contractual maturities of investments in debt securities at December
31, 1996:
(in millions) Cost Fair Value
1 year to 5 years $ 2 $ 2
5 years to 10 years 3 3
Due after 10 years 24 25
----- -----
$29 $30
Exhibit 99-3
SUPPLEMENTAL CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
OVERVIEW
Ameren Corporation (Ameren) is a newly created holding company which will
be registered under the Public Utility Holding Company Act of 1935 (PUHCA).
In December 1997, Union Electric Company (AmerenUE) and CIPSCO Incorporated
(CIPSCO) combined to form Ameren, with AmerenUE and CIPSCO's subsidiaries,
Central Illinois Public Service Company (AmerenCIPS) and CIPSCO Investment
Company (CIC) becoming wholly-owned subsidiaries of Ameren (the Merger).
In addition, Ameren, as a result of the Merger, has a 60 percent ownership
interest in Electric Energy, Inc. (EEI), which is consolidated for
financial reporting purposes. Upon consummation of the Merger, the common
stockholders of AmerenUE and CIPSCO received one and 1.03 shares,
respectively, of Ameren common stock, par value $.01 per share, and became
common stockholders of Ameren.
The Merger is accounted for as a pooling-of-interests, and the Supplemental
Consolidated Condensed Financial Statements included in this Form 8-K, in
lieu of pro forma financial statements as required by Article ll, "Pro
Forma Financial Information" of Regulation S-X, are presented as if the
Merger were consummated as of the beginning of the earliest period
presented. However, the Supplemental Consolidated Condensed Financial
Statements are not necessarily indicative of the results of operations,
financial position or cash flows that would have occurred had the Merger
been consummated for the periods for which it is given effect, nor is it
necessarily indicative of the future results of operations, financial
position or cash flows.
References to the Company are to Ameren on a consolidated basis; however,
in certain circumstances, the subsidiaries are separately referred to in
order to distinguish between their different business activities.
RESULTS OF OPERATIONS
Earnings
Common stock earnings for the nine months ended September 30, 1997 totaled
$340 million, or $2.48 per share, compared to earnings of $348 million or
$2.53 per share for the same period in 1996. Earnings and earnings per
share fluctuated due to many conditions, primarily: weather variations,
competitive market forces, credits to electric customers, sales growth,
fluctuating operating expenses, and merger-related expenses.
Electric Operations
The impacts of the more significant items affecting electric revenues and
operating expenses during the nine month period ended September 30, 1997
compared to 1996 are detailed below:
Electric Revenues
(millions of dollars) Variation for period ended
September 30, 1997 from
comparable
prior year period
Nine
Months
Rate variations $ (4)
Credits to customers 26
Effect of abnormal weather (3)
Growth and other (3)
Interchange sales (6)
EEI 5
____
$ 15
Electric revenues for the nine months ended September 30, 1997 increased
$15 million compared to the same period last year primarily due to a lower
customer credit (see Note 2 - Regulatory Matters under Notes to the
Supplemental Consolidated Condensed Financial Statements), partly offset by
decreases in interchange revenues and lower revenues attributable to one
less day in the period due to leap year in 1996. For the nine month period
ended September 30, 1997, residential sales decreased 2 percent while
commercial sales remained relatively flat compared to the same periods in
1996. Industrial sales increased 1 percent while interchange sales
decreased 1 percent compared to the year-ago periods.
Fuel and Purchased Power
(Millions of dollars) Variation for period ended
September 30, 1997 from
comparable
prior period
Nine
Months
Fuel:
Variation in generation $ 26
Price (20)
Generation efficiencies and other --
Purchased power variation (37)
EEI 9
___
$(22)
___
The decline in fuel and purchased power costs for the nine months ended
September 30, 1997, versus the comparable prior-year period was primarily
due to decreased purchased power costs, resulting from relatively flat
native load sales coupled with greater generation, as well as lower fuel
prices.
Gas Operations
The decrease in gas revenues of $2 million for the nine months ended
September 30, 1997 compared to the comparable year-ago period was primarily
due to milder weather. Dekatherm sales to residential and commercial
customers decreased 12 percent and 17 percent, respectively, in the nine
month period ended September 30, 1997 over the same period in 1996, offset
in part by increased dekatherm sales to industrial customers by 19 percent.
In addition to traditional sales to its end customers, AmerenCIPS makes off-
system sales of gas to others. Such off-system sales in 1997 continued to
offset above mentioned declines, whereas such sales were minimal in 1996.
The $4 million increase in gas costs for the nine months ended September
30, 1997 when compared to the same period in 1996 was primarily the result
of increased dekatherms purchased for resale to wholesale customers.
Other Operating Expenses
Other operating expense variations reflect recurring conditions such as
growth, inflation and wage increases.
For the nine months ended September 30, 1997, other operating expenses
increased $34 million versus the comparable prior year period primarily due
to increased consultant expenses, computer related expenses, and injuries
and damages expenses.
Depreciation and amortization expense for the nine months ended September
30, 1997 increased $7 million compared to the comparable 1996 period
primarily due to increases in depreciable property.
Income taxes charged to operating expenses for the nine months ended
September 30, 1997 decreased $11 million compared to the same period in
1996 primarily as the result of lower pretax income.
Other Income and Deductions
Miscellaneous, net for the nine months ended September 30, 1997 decreased
$3 million compared to the nine month period ended September 30, 1996 due
to an increase in merger-related expenses.
Interest
Interest charges for the nine months ended September 30, 1997 increased $5
million compared to the same period in 1996 primarily due to increased debt
outstanding.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $625 million for the nine
months ended September 30, 1997, compared to $662 million during the same
1996 period.
Cash flows used in investing activities totaled $293 million and $333
million for the nine months ended September 30, 1997 and 1996,
respectively. Construction expenditures for the nine months ended
September 30, 1997 of $287 million were for constructing new or improving
existing facilities, purchasing railroad coal cars and complying with the
Clean Air Act. In addition, the Company expended $13 million for the
acquisition of nuclear fuel. Capital requirements for the remainder of
1997 are expected to be principally for construction expenditures and the
acquisition of nuclear fuel.
Cash flows used in financing activities were $285 million for the nine
months ended September 30, 1997, compared to $297 million of cash flows
used for financing activities during the same 1996 period. The Company's
principal financing activities for the nine months ended September 30,
1997, were the redemption of $106 million of long-term debt and $64 million
of preferred stock and the payment of dividends.
The Company plans to utilize short-term debt as support for normal
operations and other temporary requirements. AmerenUE and AmerenCIPS are
authorized by the Federal Energy Regulatory Commission (FERC) to have up to
$600 million and $150 million, respectively, of short-term unsecured debt
instruments outstanding at any one time. Short-term borrowings consist of
bank loans (maturities generally on an overnight basis) and commercial
paper (maturities generally within 10 to 45 days). At September 30, 1997,
the Company had committed bank lines of credit aggregating $259 million (of
which $252 million were unused at that date) which make available interim
financing at various rates of interest based on LIBOR, the bank certificate
of deposit rate or other options. The lines of credit are renewable
annually at various dates throughout the year. As of September 30, 1997,
the Company had $43 million of short-term borrowings.
As of September 30, 1997, AmerenCIPS has registration statements covering
$75 million of first mortgage bonds and medium-term notes filed with the
Securities and Exchange Commission (SEC). AmerenCIPS' mortgage indenture
limits the amount of first mortgage bonds which may be issued. At
September 30, 1997, AmerenCIPS could have issued about $677 million of
additional first mortgage bonds under the indenture, assuming an annual
interest rate of 7.5 percent. Additionally, AmerenCIPS' articles of
incorporation limit amounts of preferred stock which may be issued.
Assuming a preferred dividend rate of 7.38 percent, the utility could have
issued all $185 million of authorized but unissued preferred stock as of
September 30, 1997. AmerenUE has registration statements covering $160
million of long-term debt filed with the SEC. In addition, AmerenUE has
registration statements filed with the SEC covering $100 million of
preferred stock. AmerenUE also has bank credit agreements due 1999 which
permit the borrowing of up to $300 million and $200 million on a long-term
basis. At September 30, 1997, no such borrowings were outstanding.
Additionally, AmerenUE has a lease agreement which provides for the
financing of nuclear fuel. At September 30, 1997, the maximum amount which
could be financed under the agreement was $120 million. Cash provided from
financing for the nine months ended September 30, 1997, included issuances
under the lease for nuclear fuel of $28 million offset in part by $21
million of redemptions. At September 30, 1997, $114 million was financed
under the lease.
RATE MATTERS
See Note 2 - Regulatory Matters under Notes to Supplemental Consolidated
Condensed Financial Statements for further information.
CONTINGENCIES
Subsequent to the completion of a contract restructuring with a major coal
supplier by AmerenCIPS, a group of industrial customers filed with the
Illinois Third District Appellate Court (the Court) in February 1997 an
appeal of the December 1996 order of the ICC which approved, among other
things, recovery of the restructuring payment and associated carrying costs
(Restructuring Charges), incurred as a result of the restructuring, through
the retail fuel adjustment clause (FAC). Additionally, in May 1997 the
FERC approved recovery of the wholesale portion of the Restructuring
Charges through the wholesale FAC.
As a result of the ICC and FERC orders, AmerenCIPS classified the $72
million of the Restructuring Charges made to the coal supplier in February
1997 as a regulatory asset and, through October 1997, recovered
approximately $9.5 million of the Restructuring Charges through the retail
FAC and from wholesale customers.
On November 24, 1997, the Court reversed the ICC's order, finding that the
Restructuring Charges were not direct costs of fuel that may be recovered
through the retail FAC, but rather should be considered as a part of a
review of AmerenCIPS' aggregate revenue requirements in a full rate case.
Restructuring Charges allocated to wholesale customers (approximately 16
percent of the total) are not in question as a result of the opinion of the
Court. On December 8, 1997, AmerenCIPS requested a rehearing by the Court.
The Company is evaluating the impact of the Court decision on its financial
statements. The Company cannot predict the ultimate outcome of this
matter. If the Court's decision should ultimately prevail, AmerenCIPS will
be required to cease recovery of the Restructuring Charges through the
retail FAC, and could be required to refund any portion of those charges
that had been collected through the retail FAC. The Company is also
exploring other alternatives for recovery of the Restructuring Charges.
The Company is currently evaluating the unamortized retail portion of the
Restructuring Charges, which is currently classified as a regulatory asset,
to determine if it continues to meet the criteria for the existence of an
asset under Generally Accepted Accounting Principles (GAAP). If it is
determined that such criteria are not met, the unamortized balance of the
Restructuring Charges, approximately $36 million, net of tax, could be
charged to earnings. The Company is also evaluating the revenues
previously recovered in 1997 through the retail FAC to determine if a loss
contingency, as defined under GAAP, is required. Such loss contingency ($5
million, net of tax) could also be charged to earnings. See Note 3 -
Commitments and Contingencies under Notes to Supplemental Consolidated
Condensed Financial Statements for further information.
See Note 3 - Commitments and Contingencies under Notes to Supplemental
Consolidated Condensed Financial Statements for other material issues
existing at September 30, 1997.
DIVIDENDS
The Board of Directors does not set specific targets or payout parameters
for dividend payments, however, the Board considers various issues
including the Company's historic earnings and cash flow; projected
earnings, cash flow and potential cash flow requirements; dividend
increases at other utilities; return on investments with similar risk
characteristics; and overall business considerations. It is currently
anticipated that the Company will initially pay dividends on its common
stock at AmerenUE's historical payment level, which was $2.54 per share on
an annual basis prior to the consummation of the Merger.
ELECTRIC INDUSTRY RESTRUCTURING
Certain states are considering proposals that would promote competition in
the retail electric market. In December 1997, the Governor of Illinois
signed the Electric Service Customer Choice and Rate Relief Law of 1997
(the Act) providing for utility restructuring in Illinois. This
legislation introduces price-based competition into the supply of electric
energy in Illinois and will provide a less regulated structure for Illinois
electric utilities. The Act includes a 5 percent residential electric rate
decrease for the Company's Illinois electric customers, effective August 1,
1998. The Company may be subject to additional 5 percent residential
electric rate decreases in each of 2000 and 2002 to the extent its rates
exceed the Midwest utility average at that time. The Company's rates are
currently below the Midwest utility average. The Company estimates that
the initial 5 percent rate decrease will result in a decrease in annual
electric revenues of about $13 million, based on estimated levels of sales
and assuming normal weather conditions. Retail direct access, which allows
customers to choose their electric generation supplier, will be phased in
over several years. Access for commercial and industrial customers will
occur over a period from October 1999 to December 2000, and access for
residential customers will occur after May 1, 2002. The Act also relieves
the Company of the requirement in the ICC's Order issued in September 1997
(which approved the Merger), requiring AmerenUE and AmerenCIPS to file
electric rate cases or alternative regulatory plans in Illinois following
consummation of the Merger to reflect the effects of net merger savings.
Other provisions of the Act include (1) potential recovery of a portion of
a utility's stranded costs through a transition charge collected from
customers who choose another electric supplier, (2) the option for certain
utilities, including the Company, to eliminate the retail FAC applicable to
their rates and to roll into base rates a historical level of fuel expense
and (3) a mechanism to securitize certain future revenues related to
stranded costs.
At this time, the Company is assessing the impact that the Act will have on
its operations. The potential negative consequences resulting from the Act
could be significant and include the impairment and writedown of certain
assets, including generation-related plant and regulatory assets, related
to the Company's Illinois jurisdictional assets. The provisions of the Act
could also result in lower revenues, reduced profit margins and increased
costs of capital. At this time, the Company is unable to determine the
impact of the Act on the Company's future financial condition, results of
operations or liquidity. (See Note 2 - Regulatory Matters under Notes to
Supplemental Consolidated Condensed Financial Statements.)
In Missouri, where 72 percent of the Company's retail electric revenues are
derived, a task force appointed by the Missouri Public Service Commission
(MoPSC) is investigating industry restructuring and competition and is
scheduled to issue a report to the MoPSC in 1998. A joint legislative
committee is also conducting hearings on these issues. Currently, retail
wheeling has not been allowed in Missouri; however, the joint agreement
approved by the MoPSC in February 1997 as part of its merger authorization
includes a provision that required AmerenUE to file a proposal for a 100-
megawatt experimental retail wheeling pilot program in Missouri. AmerenUE
filed its proposal with the MoPSC in September 1997. This proposal is
still subject to review and approval by the MoPSC.
The Company is unable to predict the timing or ultimate outcome of the
electric industry restructuring initiatives being considered in the state
of Missouri. In the state of Missouri, the potential negative consequences
of industry restructuring could be significant and include the impairment
and writedown of certain assets, including generation-related plant and
regulatory assets, lower revenues, reduced profit margins and increased
costs of capital. At this time, the Company is unable to predict the
impact of potential electric industry restructuring matters in the state of
Missouri on the Company's future financial condition, results of operations
or liquidity. (See Note 2 - Regulatory Matters under Notes to Supplemental
Consolidated Condensed Financial Statements.)
AIR QUALITY STANDARDS
In July 1997, the United States Environmental Protection Agency (EPA)
issued final regulations revising the National Ambient Air Quality
Standards for ozone and particulate matter. Although specific emission
control requirements are still being developed, it is believed that the
revised standards will require significant additional reductions in
nitrogen oxide and sulfur dioxide emissions from coal-fired boilers. In
October 1997, the EPA announced that Missouri and Illinois are included in
the area targeted for nitrogen oxide emissions reductions as part of their
regional control program. Reduction requirements in nitrogen oxide
emissions from the Company's coal-fired boilers could exceed 80 percent
from 1990 levels by the year 2002. Reduction requirements in sulfur
dioxide emissions may be up to 50 percent beyond that already required by
Phase II acid rain control provisions of the 1990 Clean Air Act Amendments
and are anticipated to be required by 2007. Because of the magnitude of
these additional reductions, the Company could be required to incur
significantly higher capital costs to meet future compliance obligations
for its coal-fired boilers or purchase power from other sources, either of
which could have significantly higher operating and maintenance
expenditures associated with compliance. At this time the Company is
unable to determine the impact of the revised air quality standards on the
Company's future financial condition, results of operations or liquidity.
The United States and other countries are discussing possibilities for an
international treaty to address the issue of "global warming." The Company
is unable to predict what agreements, if any, will be adopted. However,
most of the proposals under discussion could result in significantly higher
capital costs and operations and maintenance expenditures by the Company.
At this time, the Company is unable to determine the impact of these
proposals on the Company's future financial condition, results of
operations or liquidity.
INFORMATION SYSTEMS
The Year 2000 issue relates to computer systems and applications which
currently use two-digit date fields to designate a year. As the century
date change occurs, date-sensitive systems will recognize the year 2000 as
1900, or not at all. This inability to recognize or properly treat the
year 2000 may cause systems to process critical financial and operational
information incorrectly.
The Company continues to assess the impact of the Year 2000 issue on its
operations, including the development of final cost estimates for, and the
extent of programming changes required to address this issue. At this
time, the Company believes that the Year 2000 issue will not have a
material adverse effect on its financial condition, results of operations
or liquidity.
OUTLOOK
The Company's management and Board of Directors recognize that competition
will continue to increase in the future, especially in the energy supply
portion of our business. The introduction of competition into the markets,
coupled with the impact of the revised air quality standards on the
Company's operations, will result in numerous challenges and uncertainties
for Ameren and the utility industry. At this time, the Company cannot
predict the timing or impact of these matters on its future financial
condition, results of operations or liquidity.
SAFE HARBOR STATEMENT
Statements made in this report which are not based on historical facts are
forward-looking and, accordingly, involve risks and uncertainties that
could cause actual results to differ materially from those discussed.
Although such forward-looking statements have been made in good faith and
are based on reasonable assumptions, there is no assurance that the
expected results will be achieved. These statements include (without
limitation) statements as to future expectations, beliefs, plans,
strategies, objectives, legislation, events, conditions, financial
performance and dividends. In connection with the "Safe Harbor" provisions
of the Private Securities Litigation Reform Act of 1995, the Company is
providing the following cautionary statement to identify important factors
that could cause actual results to differ materially from those
anticipated. Factors include, but are not limited to, the effects of:
regulatory actions; changes in laws and other governmental actions;
competition; business and economic conditions; weather conditions; fuel
prices and availability; generation plant performance; monetary and fiscal
policies; and legal and administrative proceedings.
AMEREN CORPORATION
SUPPLEMENTAL CONSOLIDATED CONDENSED BALANCE SHEET
SEPTEMBER 30, 1997
(UNAUDITED)
(Thousands of Dollars, Except Shares)
ASSETS
Property and plant, at original
cost:
Electric $11,487,890
Gas 442,537
Other 35,960
__________
11,966,387
Less accumulated depreciation and amortization 5,228,270
__________
6,738,117
Construction work in progress:
Nuclear fuel in process 108,882
Other 128,861
__________
Total property and plant, net 6,975,860
__________
Investments and other assets:
Investments 116,008
Nuclear decommissioning trust fund 119,333
Other 61,307
__________
Total investments and other assets 296,648
__________
Current assets:
Cash and cash equivalents 58,092
Accounts receivable - trade (less allowance
for doubtful accounts of $5,202) 312,228
Unbilled revenue 84,142
Other accounts and notes receivable 62,098
Materials and supplies, at average cost -
Fossil fuel 92,374
Other 137,608
Other 35,240
__________
Total current assets 781,782
__________
Regulatory assets:
Deferred income taxes 695,782
Other 295,770
__________
Total regulatory assets 991,552
__________
Total Assets $ 9,045,842
__________
CAPITAL AND LIABILITIES
Capitalization:
Common stock, $.01 par value, authorized
400,000,000 shares - outstanding
137,215,462 shares $ 1,372
Other paid-in capital, principally
premium on common stock 1,582,938
Retained earnings 1,523,429
__________
Total common stockholders' equity 3,017,739
Preferred stock not subject to mandatory
redemption 235,197
Long-term debt 2,492,741
__________
Total capitalization 5,835,677
__________
Minority interest in consolidated subsidiary 3,534
Current liabilities:
Current maturity of long-term debt 43,193
Short-term debt 43,358
Accounts and wages payable 184,248
Accumulated deferred income taxes 35,160
Taxes accrued 249,822
Other 180,373
__________
Total current liabilities 736,154
__________
Accumulated deferred income taxes 1,635,289
Accumulated deferred investment tax credits 202,099
Regulatory liability 285,612
Other deferred credits and liabilities 347,477
__________
Total Capital and Liabilities $ 9,045,842
__________
See Notes to Supplemental Consolidated Condensed Financial Statements
AMEREN CORPORATION
SUPPLEMENTAL CONSOLIDATED CONDENSED
STATEMENTS OF INCOME
NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996
(UNAUDITED)
(Thousands of Dollars, Except Shares and Per Share Amounts)
1997 1996
OPERATING REVENUES:
Electric $2,421,692 $2,406,283
Gas 167,899 169,557
Other 9,771 8,776
_________ _________
Total operating revenues 2,599,362 2,584,616
OPERATING EXPENSES:
Operations
Fuel and purchased power 638,297 660,732
Gas costs 106,909 102,682
Other 434,067 400,522
--------- ---------
1,179,273 1,163,936
Maintenance 219,795 216,150
Depreciation and amortization 263,608 256,252
Income taxes 227,735 238,934
Other taxes 211,905 211,471
_________ _________
Total operating expenses 2,102,316 2,086,743
OPERATING INCOME 497,046 497,873
OTHER INCOME AND DEDUCTIONS:
Allowance for equity funds
used during construction 3,395 5,156
Miscellaneous, net (15,141) (12,523)
_________ _________
Total other income and deductions,
net (11,746) (7,367)
_________ _________
INCOME BEFORE INTEREST CHARGES
AND PREFERRED DIVIDENDS 485,300 490,506
INTEREST CHARGES AND PREFERRED
DIVIDENDS:
Interest 141,262 136,060
Allowance for borrowed funds used
during construction (5,443) (5,919)
Preferred dividends of subsidiaries 9,395 12,730
_________ _________
Net interest charges and preferred
dividends 145,214 142,871
_________ _________
NET INCOME $ 340,086 $ 347,635
_________ _________
EARNINGS PER SHARE OF COMMON
STOCK (BASED ON AVERAGE SHARES
OUTSTANDING) $2.48 $2.53
____ ____
AVERAGE COMMON SHARES OUTSTANDING 137,215,462 137,215,462
___________ ___________
See Notes to Supplemental Consolidated Condensed Financial Statements
AMEREN CORPORATION
SUPPLEMENTAL CONSOLIDATED CONDENSED
STATEMENT OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996
(UNAUDITED)
(Thousands of Dollars)
1997 1996
Cash Flows From Operating:
Net income $340,086 $347,635
Adjustments to reconcile net income to
net cash provided by operating
activities:
Depreciation and amortization 259,371 252,350
Amortization of nuclear fuel 28,737 32,198
Allowance for funds used during
construction (8,838) (11,075)
Deferred income taxes, net (4,479) 11,675
Deferred investment tax credits, net (7,128) (7,150)
Coal contract restructuring charge (71,795)
Changes in assets and liabilities:
Receivables, net (22,722) (18,210)
Materials and supplies 14,124 (22,862)
Accounts and wages payable (112,839) (110,215)
Taxes accrued 184,585 150,258
Other, net 25,865 37,763
_______ _______
Net cash provided by operating activities 624,967 662,367
Cash Flows From Investing:
Construction expenditures (286,952) (312,528)
Allowance for funds used during construction 8,838 11,075
Nuclear fuel expenditures (12,594) (26,001)
Long-term investments (2,698) (5,282)
_______ _______
Net cash used in investing activities (293,406) (332,736)
_______ _______
Cash Flows From Financing:
Dividends on common stock (248,376) (244,291)
Redemptions -
Nuclear fuel lease (21,011) (25,659)
Short-term debt (25,710) (29,600)
Long-term debt (106,000) (35,000)
Preferred stock (63,924) (26)
Issuances -
Nuclear fuel lease 27,653 31,581
Short-term debt -- 6,070
Long-term debt 152,000 --
_______ _______
Net cash used in financing activities (285,368) (296,925)
Net change in cash and cash equivalents 46,193 32,706
Cash and cash equivalents at beginning of
period 11,899 2,378
_______ _______
Cash and cash equivalents at end of period $ 58,092 $ 35,084
_______ _______
Cash paid during the periods:
Interest (net of amount capitalized) $108,910 $115,340
Income taxes $120,829 $146,942
_______ _______
See Notes to Supplemental Consolidated Condensed Financial Statements
AMEREN CORPORATION
NOTES TO SUPPLEMENTAL CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
SEPTEMBER 30, 1997
NOTE 1 - Summary of Significant Accounting Policies
Merger and Supplemental Financial Statements (Basis of Presentation)
Effective December 31, 1997, following the receipt of all required state and
federal regulatory approvals, Union Electric Company (AmerenUE) and CIPSCO
Incorporated (CIPSCO) combined to form Ameren Corporation (Ameren)(the
Merger). The accompanying supplemental consolidated condensed financial
statements (the financial statements) reflect the accounting for the Merger
as a pooling of interests and are presented as if the companies were
combined as of the earliest period presented. However, the financial
information is not necessarily indicative of the results of operations,
financial position or cash flows that would have occurred had the Merger
been consummated for the periods for which it is given effect, nor is it
necessarily indicative of future results of operations, financial position,
or cash flows. The financial statements reflect the conversion of each
outstanding share of AmerenUE common stock into one share of Ameren common
stock, and each outstanding share of CIPSCO common stock into 1.03 shares
of Ameren common stock in accordance with the terms of the merger
agreement. The outstanding preferred stock of AmerenUE and Central
Illinois Public Service Company (AmerenCIPS), a subsidiary of CIPSCO, were
not affected by the Merger.
The accompanying financial statements include the accounts of Ameren and
its consolidated subsidiaries (collectively the Company). All subsidiaries
for which the Company owns directly or indirectly more than 50% of the
voting stock are included as consolidated subsidiaries. Ameren's primary
operating companies, AmerenUE and AmerenCIPS are engaged principally in the
generation, transmission, distribution and sale of electric energy and the
purchase, distribution, transportation and sale of natural gas in the
states of Missouri and Illinois. The Company also has a non-regulated
investing subsidiary, CIPSCO Investment Company (CIC). The Company has a
60% interest in Electric Energy, Inc. (EEI). EEI owns and operates an
electric generating and transmission facility in Illinois that supplies
electric power primarily to a uranium enrichment plant located in Paducah,
Kentucky.
All significant intercompany balances and transactions have been eliminated
from the consolidated financial statements.
Financial statement note disclosures, normally included in financial
statements prepared in conformity with generally accepted accounting
principles, have been omitted in these financial statements. However, in
the opinion of the Company, the disclosures contained in the financial
statements are adequate to make the information presented not misleading.
See Notes to Supplemental Consolidated Financial Statements as of December
31, 1996, included in this Form 8-K for information relevant to the
accompanying financial statements, including information as to the
significant accounting policies of the Company.
In the opinion of the Company, the financial statements filed as a part of
this Form 8-K reflect all adjustments, consisting only of normal recurring
adjustments, necessary for a fair statement of the results for the periods
presented.
Due to the effect of weather on sales and other factors which are
characteristic of public utility operations, financial results for the
periods ended September 30, 1997 and 1996 are not necessarily indicative of
trends for any nine-month period.
Operating revenues and net income for the nine months ended September 30,
1997 and September 30, 1996, were as follows (in millions):
AmerenUE CIPSCO OTHER AMEREN
Nine months ended
September 30, 1997:
Operating revenues $1,812 $649 $138 $2,599
Net income 278 62 340
Nine months ended
September 30, 1996:
Operating revenues $1,785 $669 $131 $2,585
Net income 279 69 348
Regulation
Ameren will be a registered holding company and therefore subject to
regulation by the Securities and Exchange Commission (SEC) under the Public
Utility Holding Company Act of 1935 (PUHCA). AmerenUE and AmerenCIPS are
also regulated by the Missouri Public Service Commission (MoPSC), Illinois
Commerce Commission (ICC), and the Federal Energy Regulatory Commission
(FERC). The accounting policies of the Company are in accordance with the
ratemaking practices of the regulatory authorities having jurisdiction and,
as such, conform to Generally Accepted Accounting Principles (GAAP), as
applied to regulated public utilities.
NOTE 2 - Regulatory Matters
In July 1995, the MoPSC approved an agreement involving the Company's
Missouri electric rates. The agreement decreased rates 1.8% for all
classes of Missouri retail electric customers, effective August 1, 1995,
reducing annual revenues by about $30 million and reducing annual earnings
by approximately 13 cents per share. In addition, a one-time $30 million
credit to retail Missouri electric customers reduced 1995 earnings
approximately 13 cents per share. Also included is a three-year
experimental alternative regulation plan that provides that earnings in any
future years in excess of a 12.61% regulatory return on equity (ROE) will
be shared equally between customers and stockholders, and earnings above a
14% ROE will be credited to customers. The formula for computing the
credit uses twelve-month results ending June 30, rather than calendar year
earnings. The agreement also provides that no party shall file for a
general increase or decrease in the Company's Missouri retail electric
rates prior to July 1, 1998, except that the Company may file for an
increase if certain adverse events occur. During the nine months ended
September 30, 1997, the Company recorded an estimated $20 million credit
for the second year of the plan compared to the $47 million credit recorded
for the first year of the plan in 1996. This credit, which the Company
expects to pay to customers in 1998, was reflected as a reduction in
revenues.
Included in the joint agreement approved by the MoPSC in its February 1997
order authorizing the Merger, is a new three-year experimental alternative
regulation plan that will run from July 1, 1998, through June 30, 2001.
Like the current plan, the new plan provides that earnings over a 12.61%
ROE up to a 14% ROE will be shared equally between customers and
shareholders. The new three-year plan will also return to customers 90% of
all earnings above a 14% ROE up to a 16% ROE. Earnings above a 16% ROE
would be credited entirely to customers. Other agreement provisions
include: recovery over a 10-year period of the Missouri portion of merger-
related expenses; a Missouri electric rate decrease, effective September 1,
1998, based on the weather-adjusted average annual credits to customers
under the current experimental alternative regulation plan; and an
experimental retail wheeling pilot program for 100 megawatts of electric
power. Also, as part of the agreement, the Company will not seek to
recover in Missouri the merger premium. The exclusion of the merger
premium from rates did not result in a charge to earnings.
In September 1997, the ICC approved the Merger subject to certain
conditions. The conditions included the requirement for AmerenUE and
AmerenCIPS to file electric and gas rate cases or alternative regulatory
plans within six months after the Merger is final to determine how net
merger savings would be shared between the ratepayers and stockholders.
In December 1997, the Governor of Illinois signed the Electric Service
Customer Choice and Rate Relief Law of 1997 (the Act) providing for utility
restructuring in Illinois. This legislation introduces price-based
competition into the supply of electric energy in Illinois and will provide
a less regulated structure for Illinois electric utilities. The Act
includes a 5 percent residential electric rate decrease for the Company's
Illinois electric customers, effective August 1, 1998. The Company may be
subject to additional 5 percent residential electric rate decreases in each
of 2000 and 2002 to the extent its rates exceed the Midwest utility average
at that time. The Company's rates are currently below the Midwest utility
average. The Company estimates that the initial 5 percent rate decrease
will result in a decrease in annual electric revenues of about $13 million,
based on estimated levels of sales and assuming normal weather conditions.
Retail direct access, which allows customers to choose their electric
generation supplier, will be phased in over several years. Access for
commercial and industrial customers will occur over a period from October
1999 to December 2000, and access for residential customers will occur
after May 1, 2002. The Act also relieves the Company of the requirement in
the ICC's Order issued in September 1997 (which approved the Merger),
requiring AmerenUE and AmerenCIPS to file electric rate cases or
alternative regulatory plans in Illinois following consummation of the
Merger to reflect the effects of net merger savings. Other provisions of
the Act include (1) potential recovery of a portion of a utility's stranded
costs through a transition charge collected from customers who choose
another electric supplier, (2) the option for certain utilities, including
the Company, to eliminate the retail FAC applicable to their rates and to
roll into base rates a historical level of fuel expense and (3) a mechanism
to securitize certain future revenues related to stranded costs.
The Company's accounting policies and financial statements conform to GAAP
applicable to rate-regulated enterprises and reflect the effects of the
ratemaking process in accordance with SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation". Such effects concern mainly the
time at which various items enter into the determination of net income in
order to follow the principle of matching costs and revenues. For example,
SFAS 71 allows the Company to record certain assets and liabilities
(regulatory assets and regulatory liabilities) which are expected to be
recovered or settled in future rates and would not be recorded under GAAP
for nonregulated entities. In addition, reporting under SFAS 71 allows
companies whose service obligations and prices are regulated to maintain
assets on their balance sheets representing costs they reasonably expect to
recover from customers, through inclusion of such costs in future rates.
SFAS 101, "Accounting for the Discontinuance of Application of FASB
Statement No. 71," specifies how an enterprise that ceases to meet the
criteria for application of SFAS 71 for all or part of its operations
should report that event in its financial statements. In general, SFAS 101
requires that the enterprise report the discontinuance of SFAS 71 by
eliminating from its balance sheet all regulatory assets and liabilities
related to the applicable portion of the business. At its July 24, 1997
meeting, the Emerging Issues Task Force of the Financial Accounting
Standards Board (EITF) concluded that application of SFAS 71 accounting
should be discontinued once sufficiently detailed deregulation legislation
is issued for a separable portion of a business for which a plan of
deregulation has been established. However, the EITF further concluded
that regulatory assets associated with the deregulated portion of the
business, which will be recovered through tariffs charged to customers of a
regulated portion of the business, should be associated with the regulated
portion of the business from which future cash recovery is expected (not
the portion of the business from which the costs originated), and can
therefore continue to be carried on the regulated entity's balance sheet to
the extent such assets are recovered. In addition, SFAS 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of" establishes accounting standards for the impairment of long-
lived assets (i.e., determining whether the costs of such assets are
recoverable in future revenues.) SFAS 121 also requires that regulatory
assets, which are no longer probable of recovery through future revenue, be
charged to earnings.
Due to the enactment of the Act, prices for the supply of electric
generation are expected to transition from cost-based, regulated rates to
rates determined by competitive market forces in the state of Illinois. As
a result, the Company will discontinue application of SFAS 71 for the
Illinois portion of its generating business (i.e., the portion of the
Company's business related to the supply of electric energy in Illinois) in
the fourth quarter of 1997. At this time, the Company is assessing the
impact that the Act will have on its operations. The potential negative
consequences resulting from the Act could be significant and include the
impairment and writedown of certain assets, including generation-related
plant and regulatory assets, related to the Company's Illinois
jurisdictional assets. At September 30, 1997, the Company's net investment
in generation facilities related to its Illinois jurisdiction approximated
$826 million and was included in electric plant-in service on the Company's
balance sheet. In addition, at September 30, 1997, the Company's Illinois
generation-related net regulatory assets approximated $166 million. The
provisions of the Act could also result in lower revenues, reduced profit
margins and increased costs of capital. At this time, the Company is
unable to determine the impact of the Act on the Company's future financial
condition, results of operations or liquidity.
In the state of Missouri, where approximately 72 percent of the Company's
retail electric revenues are derived, a task force appointed by the MoPSC
is conducting studies of electric industry restructuring and competition
and will issue a report to the MoPSC in April 1998. A joint legislative
committee is also conducting studies and will report its findings and
recommendations to the Missouri General Assembly after reviewing the
results of the MoPSC task force.
The Company is unable to predict the timing or ultimate outcome of the
electric industry restructuring initiatives being considered in the state
of Missouri. In the state of Missouri, the potential negative consequences
of industry restructuring could be significant and include the impairment
and writedown of certain assets, including generation-related plant and
regulatory assets, lower revenues, reduced profit margins and increased
costs of capital. At September 30, 1997, the Company's net investment in
generation facilities related to its Missouri jurisdiction approximated
$2.7 billion and was included in electric plant-in service on the Company's
balance sheet. In addition, at September 30, 1997, the Company's Missouri
generation-related regulatory assets approximated $435 million. At this
time, the Company is unable to predict the impact of potential electric
industry restructuring matters in the state of Missouri on the Company's
future financial condition, results of operations or liquidity.
In April 1996, the FERC issued Order 888 and Order 889 related to the
industry's wholesale electric business. The Company filed an open access
tariff under Order 888 as part of the merger case and in July 1997, the
case was settled. In March 1997, the FERC issued Order 888A which required
the Company to refile a tariff by July 14, 1997. The terms were not
significantly different from those filed in the original tariff under Order
888.
In accordance with SFAS 71, the Company has deferred certain costs pursuant
to actions of its regulators, and is currently recovering such costs in
electric rates charged to customers.
The Company had recorded the following regulatory assets and regulatory
liability as of September 30, 1997 and December 31, 1996:
(in millions) September 30, 1997 December 31, 1996
Regulatory Assets:
Income taxes $696 $734
Callaway costs 108 111
Coal contract restructuring charge 66 --
Undepreciated plant costs 37 41
Unamortized loss on reacquired debt 40 42
Contract termination costs 14 20
DOE decommissioning assessment 17 18
Other 14 12
___ ___
Regulatory Assets $992 $978
___ ___
Regulatory Liability:
Income taxes $286 $304
___ ___
Regulatory Liability $286 $304
___ ___
The Company continually assesses the recoverability of its regulatory
assets. Under current accounting standards, regulatory assets are written
off to earnings when it is no longer probable that such amounts will be
recovered through future revenues. However, as noted in the above
paragraphs, electric industry restructuring legislation may impact the
recoverability of regulatory assets in the future.
NOTE 3 - Commitments and Contingencies
During 1996, AmerenCIPS restructured its contract with one of its major
coal suppliers. In 1997, AmerenCIPS paid a $70 million restructuring
charge to the supplier, which allows them to purchase at market prices low-
sulfur, out-of-state coal through the supplier (in substitution for the
high-sulfur Illinois coal AmerenCIPS was obligated to purchase under the
original contract); and would receive options for future purchases of low-
sulfur, out-of-state coal from the supplier through 1999 at set negotiated
prices.
By switching to low-sulfur coal, AmerenCIPS was able to discontinue
operating the Newton Power Plant Unit 1 scrubber. The benefits of the
restructuring include lower cost coal, avoidance of significant capital
expenditures to renovate the scrubber, and elimination of scrubber
operating and maintenance costs (offset by scrubber retirement expenses).
The net benefits of restructuring are expected to exceed $100 million over
the next 10 years. In December 1996, the ICC entered an order approving
the switch to out-of-state coal, recovery of the restructuring payment plus
associated carrying costs (Restructuring Charges) through the retail FAC
over six years, and continued recovery in rates of the undepreciated
scrubber investment plus costs of removal. A group of industrial customers
filed with the Illinois Third District Appellate Court (the Court) in
February 1997 an appeal of the December 1996 order of the ICC which
approved, among other things, recovery of the Restructuring Charges through
the retail FAC. Additionally, in May 1997 the FERC approved recovery of
the wholesale portion of the Restructuring Charges through the wholesale
FAC.
As a result of the ICC and FERC orders, AmerenCIPS classified the $72
million of the Restructuring Charges made to the coal supplier in February
1997 as a regulatory asset and, through October 1997, recovered
approximately $9.5 million of the Restructuring Charges through the retail
FAC and from wholesale customers.
On November 24, 1997, the Court reversed the ICC's order, finding that the
Restructuring Charges were not direct costs of fuel that may be recovered
through the retail FAC, but rather should be considered as a part of a
review of AmerenCIPS' aggregate revenue requirements in a full rate case.
Restructuring Charges allocated to wholesale customers (approximately 16
percent of the total) are not in question as a result of the opinion of the
Court. On December 8, 1997, AmerenCIPS requested a rehearing by the Court.
The Company is evaluating the impact of the Court decision on its financial
statements. The Company cannot predict the ultimate outcome of this
matter. If the Court's decision should ultimately prevail, AmerenCIPS will
be required to cease recovery of the Restructuring Charges through the
retail FAC, and could be required to refund any portion of those charges
that had been collected through the retail FAC. The Company is also
exploring other alternatives for recovery of the Restructuring Charges.
The Company is currently evaluating the unamortized retail portion of the
Restructuring Charges, which is currently classified as a regulatory asset,
to determine if it continues to meet the criteria for the existence of an
asset under GAAP. If it is determined that such criteria are not met, the
unamortized balance of the Restructuring Charges, approximately $36
million, net of tax, could be charged to earnings. The Company is also
evaluating the revenues previously recovered in 1997 through the retail FAC
to determine if a loss contingency, as defined under GAAP, is required.
Such loss contingency ($5 million, net of tax) could also be charged to
earnings.
Under the Clean Air Act Amendments of 1990, the Company is required to
reduce total annual sulfur dioxide emissions significantly by the year
2000. Significant reductions in nitrogen oxide are also required. By
switching to low-sulfur coal and early banking of emission credits, the
Company anticipates that it can comply with the requirements of the law
without significant revenue increases because the related capital costs are
largely offset by lower fuel costs. As of year-end 1996, estimated
remaining capital costs expected to be incurred pertaining to Clean Air Act-
related projects totaled $76 million.
In July 1997, the United States Environmental Protection Agency (EPA)
issued final regulations revising the National Ambient Air Quality
Standards for ozone and particulate matter. Although specific emission
control requirements are still being developed, it is believed that the
revised standards will require significant additional reductions in
nitrogen oxide and sulfur dioxide emissions from coal-fired boilers. In
October 1997, the EPA announced that Missouri and Illinois are included in
the area targeted for nitrogen oxide emissions reductions as part of their
regional control program. Reduction requirements in nitrogen oxide
emissions from the Company's coal-fired boilers could exceed 80 percent
from 1990 levels by the year 2002. Reduction requirements in sulfur
dioxide emissions may be up to 50 percent beyond that already required by
Phase II acid rain control provisions of the 1990 Clean Air Act Amendments
and are anticipated to be required by 2007. Because of the magnitude of
these additional reductions, the Company could be required to incur
significantly higher capital costs to meet future compliance obligations
for its coal-fired boilers or purchase power from other sources, either of
which could have significantly higher operating and maintenance
expenditures associated with compliance. At this time the Company is
unable to determine the impact of the revised air quality standards on the
Company's future financial condition, results of operations or liquidity.
The United States and other countries are discussing possibilities for an
international treaty to address the issue of "global warming." The Company
is unable to predict what agreements, if any, will be adopted. However,
most of the proposals under discussion could result in significantly higher
capital costs and operations and maintenance expenditures by the Company.
At this time, the Company is unable to determine the impact of these
proposals on the Company's future financial condition, results of
operations or liquidity.
As of September 30, 1997, AmerenUE was designated a potentially responsible
party (PRP) by federal and state environmental protection agencies at four
hazardous waste sites. Other hazardous waste sites have been identified
for which AmerenUE may be responsible but has not been designated a PRP.
AmerenCIPS has identified 13 sites where it and certain of its predecessors
and other affiliates previously operated facilities that manufactured gas
from coal. This manufacturing produced various potentially harmful by-
products which may remain on some sites. One site was added to the EPA
Superfund list in 1990.
Costs relating to studies and remediation at the 13 AmerenCIPS' sites and
associated legal and litigation expenses are being accrued and deferred
rather than expensed currently, pending recovery through rates or from
insurers. Through December 31, 1996, the total of the costs deferred, net
of recoveries from insurers and through environmental adjustment clause
rate riders approved by the ICC, was $11 million.
The ICC has instituted a reconciliation proceeding to review AmerenCIPS'
environmental remediation activities in 1993, 1994 and 1995 and to
determine whether the revenues collected under the riders in 1993 were
consistent with the amount of remediation costs prudently and properly
incurred. Amounts found to have been incorrectly included under the riders
would be subject to refund. In mid-1997, AmerenCIPS and the ICC Staff
submitted a stipulation with regard to all matters at issue. Under the
stipulation, as of December 31, 1995, the aggregate amount of (i) revenues
received under the riders, insurance proceeds (and related interest)
exceeded (ii) rider-related costs (and related carrying costs) by
approximately $4 million. If this stipulation is approved by the ICC, this
amount would be applied to cover a portion of future remediation costs.
Also, if the stipulation is approved, insurance proceeds of approximately
$3 million would be applied to cover non-rider related costs incurred.
During 1997, the accumulated balance of recoverable environmental
remediation costs exceeded the balance of available insurance proceeds and
rider revenues; therefore, AmerenCIPS began to again collect revenue under
the riders beginning November 1, 1997.
The Company continually reviews remediation costs that may be required for
all of these sites. Any unrecovered environmental costs are not expected
to have a material adverse effect on the Company's financial position,
results of operations or liquidity.
The International Union of Operating Engineers Local 148 and the
International Brotherhood of Electrical Workers Local 702 filed unfair
labor practice charges with the National Labor Relations Board (NLRB)
relating to the legality of the lockout by AmerenCIPS of both unions during
1993. The NLRB has issued complaints against AmerenCIPS concerning its
lockout. Both unions seek, among other things, back pay and other benefits
for the period of the lockout. The Company estimates the amount of back
pay and other benefits for both unions to be less than $17 million. An
administrative law judge of the NLRB has ruled that the lockout was
unlawful. On July 23, 1996, the Company appealed to the NLRB. The Company
believes the lockout was both lawful and reasonable and that the final
resolution of the disputes will not have a material adverse effect on
financial position, results of operations or liquidity of the Company.
Regulatory changes enacted and being considered at the federal and state
levels continue to change the structure of the utility industry and utility
regulation, as well as encourage increased competition. At this time, the
Company is unable to predict the impact of these changes on the Company's
future financial condition, results of operations or liquidity. See Note 2
- - Regulatory Matters for further discussion.
The Company is involved in other legal and administrative proceedings
before various courts and agencies with respect to matters arising in the
ordinary course of business, some of which involve substantial amounts.
The Company believes that the final disposition of these proceedings will
not have a material adverse effect on its financial position, results of
operations or liquidity.
Report of Independent Accountants
To the Stockholders and
Board of Directors of
Ameren Corporation
In our opinion, based upon our audits and the reports of other auditors, the
accompanying supplementary consolidated balance sheets and the related
supplementary consolidated statements of income, of cash flows and retained
earnings present fairly, in all material respects, the financial position
of Ameren Corporation and its subsidiaries at December 31, 1996 and 1995, and
the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1996, in conformity with generally
accepted accounting principles. these financial statements are the
responsibility of the Company's management; our responsibility is to ezpress an
opinion on these financial statements based on our audits. We did not audit
the financial statements of Central Illinois Public Service Company and
CIPSCO Investment Company, wholly-owned subsidiaries, which combined
statements reflect total assets of $1,871,656,000 and $1,827,911,000 at
December 31, 1996 and 1995, respectively, and total revenues of $896,715,000,
$842,262,000 and $844,615,000 for the three years in the period ended
December 31, 1996, respectively. Those statements were audited by other auditors
whose reports thereon have been furnished to us, and our opinion expressed
herein, insofar as it relates to the amounts included for Central Illinois
Public Service Compnay and CIPSCO Investment Company, is based solely on the
reports of the other auditors. We conucted our audits of these statements in
accordance with generally accepted auditing standards which require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements, assessing the accounting principles used
and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits and the reports
of other auditors provide a reasonable basis for the opinion expressed above.
/s/ PRICE WATERHOUSE LLP
________________________
PRICE WATERHOUSE LLP
St. Louis, Missouri
December 17, 1997
