<PAGE> 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of report (Date of earliest event reported):
December 31, 1997
AMEREN CORPORATION
(Exact name of registrant as specified in its charter)
Missouri 43-1723446
(State or other jurisdiction (Commission (I.R.S. Employer
of incorporation) File Number) Identification No.)
1901 Chouteau Avenue, St. Louis, Missouri 63103
(Address of principal executive offices and Zip Code)
Registrant's telephone number, including area code: (314) 621-3222
<PAGE> 2
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), 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, 1997, June 30, 1997, and
September 30, 1997.
3. Union Electric Company's Current 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, 1997, June 30, 1997, and September 30, 1997.
6. Central Illinois Public Service Company's Current Reports on
Form 8-K, dated March 20, June 1, November 24, December 16,
and December 31, 1997.
7. CIPSCO Incorporated's Current Reports on Form 8-K, dated
March 20, November 24, December 16, and December 31, 1997.
Exhibits:
All exhibits are listed in the Exhibit Index on Page 4.
- 2 -
<PAGE> 3
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.
AMEREN CORPORATION
(Registrant)
By /s/ Donald E. Brandt
------------------------------
Donald E. Brandt
Senior Vice President, Finance
Date: January 2, 1998
- 3 -
<PAGE> 4
Exhibit Index
<TABLE>
<CAPTION>
Exhibit No. Description
- - ----------- -----------
<S> <C>
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 Financial Data Schedule - Period ending December 31, 1996.
27-2 Financial Data Schedule - Period ending September 30, 1997.
99-1 News Release of Ameren Corporation, dated December 31, 1997.
99-2 Supplemental Consolidated Financial Statements.
99-3 Supplemental Consolidated Condensed Quarterly Financial Statements.
</TABLE>
- 4 -
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 6,951,106
<OTHER-PROPERTY-AND-INVEST> 209,911
<TOTAL-CURRENT-ASSETS> 729,175
<TOTAL-DEFERRED-CHARGES> 64,655
<OTHER-ASSETS> 977,720
<TOTAL-ASSETS> 8,932,567
<COMMON> 1,372
<CAPITAL-SURPLUS-PAID-IN> 1,583,728
<RETAINED-EARNINGS> 1,431,295
<TOTAL-COMMON-STOCKHOLDERS-EQ> 3,016,395
598
298,497
<LONG-TERM-DEBT-NET> 2,272,730
<SHORT-TERM-NOTES> 11,300
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 57,768
<LONG-TERM-DEBT-CURRENT-PORT> 103,000
26
<CAPITAL-LEASE-OBLIGATIONS> 77,168
<LEASES-CURRENT> 28,966
<OTHER-ITEMS-CAPITAL-AND-LIAB> 3,066,119
<TOT-CAPITALIZATION-AND-LIAB> 8,932,567
<GROSS-OPERATING-REVENUE> 3,333,505
<INCOME-TAX-EXPENSE> 254,869
<OTHER-OPERATING-EXPENSES> 2,504,575
<TOTAL-OPERATING-EXPENSES> 2,759,444
<OPERATING-INCOME-LOSS> 574,061
<OTHER-INCOME-NET> (12,495)
<INCOME-BEFORE-INTEREST-EXPEN> 561,566
<TOTAL-INTEREST-EXPENSE> 172,912
<NET-INCOME> 371,684
16,970
<EARNINGS-AVAILABLE-FOR-COMM> 371,684
<COMMON-STOCK-DIVIDENDS> 344,411
<TOTAL-INTEREST-ON-BONDS> 145,543
<CASH-FLOW-OPERATIONS> 788,683
<EPS-PRIMARY> 2.71
<EPS-DILUTED> 2.71
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 6,975,860
<OTHER-PROPERTY-AND-INVEST> 235,341
<TOTAL-CURRENT-ASSETS> 781,782
<TOTAL-DEFERRED-CHARGES> 61,307
<OTHER-ASSETS> 991,552
<TOTAL-ASSETS> 9,045,842
<COMMON> 1,372
<CAPITAL-SURPLUS-PAID-IN> 1,582,938
<RETAINED-EARNINGS> 1,523,429
<TOTAL-COMMON-STOCKHOLDERS-EQ> 3,107,739
0
235,197
<LONG-TERM-DEBT-NET> 2,407,940
<SHORT-TERM-NOTES> 7,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 36,358
<LONG-TERM-DEBT-CURRENT-PORT> 14,444
0
<CAPITAL-LEASE-OBLIGATIONS> 84,801
<LEASES-CURRENT> 28,749
<OTHER-ITEMS-CAPITAL-AND-LIAB> 3,123,614
<TOT-CAPITALIZATION-AND-LIAB> 9,045,842
<GROSS-OPERATING-REVENUE> 2,599,362
<INCOME-TAX-EXPENSE> 227,735
<OTHER-OPERATING-EXPENSES> 1,874,581
<TOTAL-OPERATING-EXPENSES> 2,102,316
<OPERATING-INCOME-LOSS> 497,046
<OTHER-INCOME-NET> (11,746)
<INCOME-BEFORE-INTEREST-EXPEN> 485,300
<TOTAL-INTEREST-EXPENSE> 135,819
<NET-INCOME> 340,086
9,395
<EARNINGS-AVAILABLE-FOR-COMM> 340,086
<COMMON-STOCK-DIVIDENDS> 261,395
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 626,173
<EPS-PRIMARY> 2.48
<EPS-DILUTED> 2.48
</TABLE>
<PAGE> 1
EXHIBIT 99-1
AMEREN 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."
--more--
<PAGE> 2
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 (AEE) for each Union Electric share (NYSE: UEP) they hold.
Holders of CIPSCO 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 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, 1997. 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.
<PAGE> 1
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:
<TABLE>
<CAPTION>
Electric Revenues Variations from Prior Year
- - -----------------------------------------------------------------------------------------------------
(Millions of Dollars) 1996 1995 1994
- - -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- - -----------------------------------------------------------------------------------------------------
</TABLE>
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.
<PAGE> 2
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.
<TABLE>
<CAPTION>
Fuel and Purchased Power Variations from Prior Year
- - ----------------------------------------------------------------------------------------------------------
(Millions of Dollars) 1996 1995 1994
- - ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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)
- - ----------------------------------------------------------------------------------------------------------
</TABLE>
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
2
<PAGE> 3
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.
3
<PAGE> 4
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
4
<PAGE> 5
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.
5
<PAGE> 6
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,
6
<PAGE> 7
(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
7
<PAGE> 8
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.
8
<PAGE> 9
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 express 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 Company and CIPSCO
Investment Company, is based solely on the reports of the other auditors. We
conducted 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
9
<PAGE> 10
AMEREN CORPORATION
SUPPLEMENTAL CONSOLIDATED BALANCE SHEET
(Thousands of Dollars, Except Shares)
<TABLE>
<CAPTION>
December 31, December 31,
ASSETS 1996 1995
- - ------ ---- ----
<S> <C> <C>
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 298,497 298,497
Note 4)
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
=========== ===========
</TABLE>
See Notes to Supplemental Consolidated Financial Statements
10
<PAGE> 11
AMEREN CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars, Except Shares and Per Share Amounts)
<TABLE>
<CAPTION>
December 31, December 31, December 31,
For the year ended 1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
OPERATING REVENUES:
Electric $ 3,013,527 $ 3,066,940 $ 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
============= ============= =============
</TABLE>
See Notes to Supplemental Consolidated Financial Statements
11
<PAGE> 12
AMEREN CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
<TABLE>
<CAPTION>
December 31, December 31 December 31,
For the year ended 1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
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 327,859 315,515 338,649
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
- - ----------------------------------------------------------------------------------------
</TABLE>
See Notes to Supplemental Consolidated Financial Statements
12
<PAGE> 13
AMEREN CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENT OF RETAINED EARNINGS
(Thousands of Dollars)
<TABLE>
<CAPTION>
- - ------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1996 1995 1994
- - ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- - ------------------------------------------------------------------------------------------------------------
</TABLE>
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)
<TABLE>
<CAPTION>
- - ------------------------------------------------------------------------------------------------
Operating Operating Net Earnings Per
Revenues Income Income Common
QUARTER ENDED Share
- - ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
- - ------------------------------------------------------------------------------------------------
</TABLE>
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
13
<PAGE> 14
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):
<TABLE>
<CAPTION>
AmerenUE CIPSCO OTHER AMEREN
-------- ------ ----- ------
<S> <C> <C> <C> <C>
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
</TABLE>
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
14
<PAGE> 15
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.
15
<PAGE> 16
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
16
<PAGE> 17
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.
17
<PAGE> 18
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.
<TABLE>
<CAPTION>
At December 31, the Company had recorded the following regulatory assets and
regulatory liability:
- - ------------------------------------------------------------------------------------------
(in millions) 1996 1995
- - ------------------------------------------------------------------------------------------
<S> <C> <C>
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
- - ------------------------------------------------------------------------------------------
</TABLE>
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.
18
<PAGE> 19
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).
<TABLE>
<CAPTION>
Outstanding preferred stock is redeemable at the redemption prices shown below:
- - ---------------------------------------------------------------------------------------------------------------
- - ---------------------------------------------------------------------------------------------------------------
December 31, 1996 1995
(in millions) (in millions)
- - ---------------------------------------------------------------------------------------------------------------
PREFERRED STOCK NOT SUBJECT TO MANDATORY
REDEMPTION:
- - ---------------------------------------------------------------------------------------------------------------
Preferred stock outstanding without par value
(entitled to cumulative dividends)
Redemption Price
(per share)
<S> <C> <C> <C> <C>
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 - note (d) 100.00 30 30
</TABLE>
19
<PAGE> 20
<TABLE>
<S> <C> <C> <C>
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
- - --------------------------------------------------------------------------------------------------------------
</TABLE>
(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 October 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:
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------------------
(in millions) 1996 1995
- - --------------------------------------------------------------------------------------------
First Mortgage Bonds - note (a)
- - --------------------------------------------------------------------------------------------
<S> <C> <C>
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
</TABLE>
20
<PAGE> 21
<TABLE>
<S> <C> <C>
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 Premium on Debt (13) (12)
- - ----------------------------------------------------------------------------------------------
Maturities Due Within One Year (146) (69)
- - ----------------------------------------------------------------------------------------------
Total Long-Term Debt $2,335 $2,373
- - ----------------------------------------------------------------------------------------------
</TABLE>
(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.
<TABLE>
<CAPTION>
Maturities of long-term debt through 2001 are as follows:
- - --------------------------------------------------------------------------
(in millions) Principal Amount
- - --------------------------------------------------------------------------
<S> <C> <C>
1997 $146
1998 43
1999 164
2000 39
2001 14
- - --------------------------------------------------------------------------
</TABLE>
Amounts for years subsequent to 1998 do not include nuclear fuel lease payments
since the amounts of such payments are not currently determinable.
21
<PAGE> 22
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).
<TABLE>
<CAPTION>
Principal reasons such rates differ from the statutory federal rate:
- - -------------------------------------------------------------------------------------------------
1996 1995 1994
- - -------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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%
- - -------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Income tax expense components:
- - ----------------------------------------------------------------------------------------
(in millions) 1996 1995 1994
- - ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- - ----------------------------------------------------------------------------------------
</TABLE>
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.
<TABLE>
<CAPTION>
Temporary differences gave rise to the following deferred tax assets and
deferred tax liabilities at December 31:
- - --------------------------------------------------------------------------------------------------------------
(in millions) 1996 1995
- - --------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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
- - --------------------------------------------------------------------------------------------------------------
</TABLE>
22
<PAGE> 23
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:
<TABLE>
<CAPTION>
Funded Status of Pension Plans
- - -------------------------------------------------------------------------------------------------------------
(in millions) 1996 1995 1994
- - -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- - -------------------------------------------------------------------------------------------------------------
</TABLE>
(*) Plan assets consist principally of common stocks and fixed income
securities.
<TABLE>
<CAPTION>
Components of Net Pension Expense
- - -------------------------------------------------------------------------------------------------------------
(in millions) 1996 1995 1994
- - -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- - -------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Assumptions for Actuarial Present Value of Projected Benefit Obligations:
- - -------------------------------------------------------------------------------------------------------------
1996 1995 1994
- - -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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%
- - -------------------------------------------------------------------------------------------------------------
</TABLE>
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:
23
<PAGE> 24
<TABLE>
<CAPTION>
Funded Status of Pension Plans
- - -------------------------------------------------------------------------------------------------------------
(in millions) 1996 1995 1994
- - -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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)
- - -------------------------------------------------------------------------------------------------------------
</TABLE>
(*) Plan assets consist principally of common and preferred stocks, bonds,
money market instruments and real estate.
<TABLE>
<CAPTION>
Components of Net Pension Expense
- - ------------------------------------------------------------------------------------------------------------
(in millions) 1996 1995 1994
- - ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- - ------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Assumptions for Actuarial Present Value of Projected Benefit Obligations
- - ----------------------------------------------------------------------------------------------------------
1996 1995 1994
- - ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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%
- - ----------------------------------------------------------------------------------------------------------
</TABLE>
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.
24
<PAGE> 25
<TABLE>
<CAPTION>
Funded Status of the Plans
- - ------------------------------------------------------------------------------------------------------------
(in millions) 1996 1995 1994
- - ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- - ------------------------------------------------------------------------------------------------------------
</TABLE>
(*) Plan assets consist principally of common stocks and fixed income
securities.
<TABLE>
<CAPTION>
Components of Postretirement Benefit Cost
- - -------------------------------------------------------------------------------------------------------------
(in millions) 1996 1995 1994
- - -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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 (1) (2) 1
(gain)/loss
Deferred gain 3 -- --
- - -------------------------------------------------------------------------------------------------------------
NET PERIODIC COST $ 44 $ 44 $ 46
- - -------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Assumptions for the Obligation Measurements
- - -------------------------------------------------------------------------------------------------------------
1996 1995 1994
- - -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- - -------------------------------------------------------------------------------------------------------------
</TABLE>
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.
25
<PAGE> 26
<TABLE>
<CAPTION>
Funded Status of the Plans
- - --------------------------------------------------------------------------------------------------------------
(in millions) 1996 1995 1994
- - --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- - --------------------------------------------------------------------------------------------------------------
</TABLE>
(*) Plan assets consist principally of common and preferred stocks, bonds,
money market instruments and real estate.
<TABLE>
<CAPTION>
Components of Postretirement Benefit Cost
- - --------------------------------------------------------------------------------------------------------------
(in millions) 1996 1995 1994
- - --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- - --------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Assumptions for the Obligation Measurements
- - ------------------------------------------------------------------------------------------------------------
1996 1995 1994
- - ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- - ------------------------------------------------------------------------------------------------------------
</TABLE>
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.
26
<PAGE> 27
<TABLE>
<CAPTION>
Summary of stock options:
- - ------------------------------------------------------------------------------------------------------------
1995
- - ------------------------------------------------------------------------------------------------------------
<S> <C>
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
- - ------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- - ------------------------------------------------------------------------------------------------------------
1996
- - ------------------------------------------------------------------------------------------------------------
<S> <C>
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
- - ------------------------------------------------------------------------------------------------------------
</TABLE>
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.
27
<PAGE> 28
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 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:
<TABLE>
<CAPTION>
TYPE AND SOURCE OF COVERAGE
- - --------------------------------------------------------------------------------------------------------
(in millions) Maximum Maximum
Coverages Assessments
for Single
Incidents
- - --------------------------------------------------------------------------------------------------------
<S> <C> <C>
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
- - --------------------------------------------------------------------------------------------------------
</TABLE>
28
<PAGE> 29
<TABLE>
<S> <C> <C>
Property Damage:
American Nuclear Insurers $ 500 $ --
Nuclear Electric Insurance Ltd. 2,250 (d) 13
- - --------------------------------------------------------------------------------------------------------
$ 2,750 $ 13
- - --------------------------------------------------------------------------------------------------------
Replacement Power:
Nuclear Electric Insurance Ltd. $ 419 (e) $ 3
- - --------------------------------------------------------------------------------------------------------
</TABLE>
(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
29
<PAGE> 30
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.
30
<PAGE> 31
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:
<TABLE>
<CAPTION>
1996 1995
- - -------------------------------------------------------------------------------------------------------
(in millions) Carrying Fair Carrying Fair
Amount Value Amount Value
- - -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
- - -------------------------------------------------------------------------------------------------------
</TABLE>
31
<PAGE> 32
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.
<TABLE>
<CAPTION>
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
- - -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Debt Securities $29 $ 2 $ -- $31
Equity Securities 40 22 -- 62
Cash equivalents 4 -- -- 4
- - -------------------------------------------------------------------------------------------------------------
$73 $24 $ -- $97
- - -------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- - -------------------------------------------------------------------------------------------------------------
1995 (in millions) Gross Unrealized
Security Type Cost Gain (Loss) Fair Value
- - -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Debt Securities $22 $ 3 $ -- $25
Equity Securities 38 9 -- 47
Cash equivalents 2 -- -- 2
- - -------------------------------------------------------------------------------------------------------------
$62 $12 $ -- $74
- - -------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
The contractual maturities of investments in debt securities at December 31,
1996:
- - ------------------------------------------------------------------------------------------------------------
(in millions) Cost Fair Value
- - ------------------------------------------------------------------------------------------------------------
<S> <C> <C>
1 year to 5 years $ 2 $ 2
5 years to 10 years 3 3
Due after 10 years 24 25
- - ------------------------------------------------------------------------------------------------------------
$29 $30
- - ------------------------------------------------------------------------------------------------------------
</TABLE>
32
<PAGE> 1
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:
<TABLE>
<CAPTION>
Electric Revenues
- - --------------------------------------------------------------------
(millions of dollars) Variation for period ended
September 30, 1997 from comparable
prior year period
- - --------------------------------------------------------------------
Nine
Months
------
<S> <C>
Rate variations $ (4)
Credits to customers 26
Effect of abnormal weather (3)
Growth and other (3)
Interchange sales (6)
EEI 5
- - --------------------------------------------------------------------
$ 15
- - --------------------------------------------------------------------
</TABLE>
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
1
<PAGE> 2
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.
<TABLE>
<CAPTION>
Fuel and Purchased Power
- - ----------------------------------------------------------------------------
(Millions of dollars) Variation for period ended
September 30, 1997 from comparable
prior period
- - ----------------------------------------------------------------------------
Nine
Months
------
<S> <C>
Fuel:
Variation in generation $ 26
Price (20)
Generation efficiencies and other --
Purchased power variation (37)
EEI 9
- - ----------------------------------------------------------------------------
$(22)
- - ----------------------------------------------------------------------------
</TABLE>
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.
2
<PAGE> 3
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
3
<PAGE> 4
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
4
<PAGE> 5
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.
5
<PAGE> 6
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.
6
<PAGE> 7
AMEREN CORPORATION
SUPPLEMENTAL CONSOLIDATED CONDENSED BALANCE SHEET
SEPTEMBER 30, 1997
(UNAUDITED)
(Thousands of Dollars, Except Shares)
<TABLE>
<S> <C>
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
===========
</TABLE>
See Notes to Supplemental Consolidated Condensed Financial Statements
7
<PAGE> 8
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)
<TABLE>
<CAPTION>
1997 1996
------------- -------------
<S> <C> <C>
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
============= =============
</TABLE>
See Notes to Supplemental Consolidated Condensed Financial Statements
8
<PAGE> 9
AMEREN CORPORATION
SUPPLEMENTAL CONSOLIDATED CONDENSED
STATEMENT OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996
(UNAUDITED)
(Thousands of Dollars)
<TABLE>
<CAPTION>
1997 1996
--------- ---------
<S> <C> <C>
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
--------- ---------
</TABLE>
See Notes to Supplemental Consolidated Condensed Financial Statements
9
<PAGE> 10
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):
<TABLE>
<CAPTION>
AmerenUE CIPSCO OTHER AMEREN
-------- ------ ------ ------
<S> <C> <C> <C> <C>
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
</TABLE>
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<PAGE> 11
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
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<PAGE> 12
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
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<PAGE> 13
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:
<TABLE>
<CAPTION>
- - -------------------------------------------------------------------------------
(in millions) September 30, 1997 December 31, 1996
- - -------------------------------------------------------------------------------
<S> <C> <C>
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
- - -------------------------------------------------------------------------------
</TABLE>
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 payment 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
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<PAGE> 14
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
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<PAGE> 15
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.
15
