UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For Quarterly Period Ended September 30, 2001
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For The Transition Period From to
Commission file number 1-14756.
AMEREN CORPORATION
(Exact name of registrant as specified in its charter)
Missouri 43-1723446
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) 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
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X . No .
-------- ---------
Shares outstanding of each of registrant's classes of common stock as of
November 13, 2001: Common Stock, $ .01 par value - 137,622,840
Ameren Corporation
Index
Page No.
Part I Financial Information
Item 1. Consolidated Financial Statements (Unaudited)
Consolidated Balance Sheet
- September 30, 2001 and December 31, 2000 11
Consolidated Statement of Income
- Three months, nine months and 12 months ended
September 30, 2001 and 2000 12
Consolidated Statement of Cash Flows
- Nine months ended September 30, 2001 and 2000 13
Consolidated Statement of Common Stockholders'
Equity - Nine months ended September 30, 2001 and
12 months ended December 31, 2000 14
Notes to Consolidated Financial Statements 15
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 2
Item 3. Quantitative and Qualitative Disclosures
About Market Risk 8
Part II Other Information
Item 1. Legal Proceedings 20
Item 5. Other Information 20
Item 6. Exhibits and Reports on Form 8-K 21
PART I - FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED).
The unaudited consolidated financial statements of Ameren Corporation (Ameren or
the Registrant) appear on pages 11 through 18 of this report.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
OVERVIEW
Ameren Corporation (Ameren or the Registrant) is a holding company registered
under the Public Utility Holding Company Act of 1935 (PUHCA). Ameren's primary
operating companies are Union Electric Company (AmerenUE), Central Illinois
Public Service Company (AmerenCIPS), both subsidiaries of Ameren, and
AmerenEnergy Generating Company (Generating Company), the nonregulated electric
generating subsidiary of AmerenEnergy Resources Company (Resources Company),
which is a subsidiary of Ameren. Ameren also has a 60 percent ownership interest
in Electric Energy, Inc. (EEI), which is consolidated for financial reporting
purposes. Ameren's other subsidiaries include AmerenEnergy, Inc. (AmerenEnergy),
Ameren Development Company, Resources Company, Ameren Services Company and
CIPSCO Investment Company. AmerenEnergy, an energy trading and marketing
subsidiary, primarily serves as a power marketing agent for AmerenUE and
Generating Company and provides a range of energy and risk management services
to targeted customers. Ameren Development Company is a nonregulated subsidiary
encompassing Ameren's nonregulated products and services. Resources Company
holds the Registrant's nonregulated generating operations. Ameren Services
Company provides shared support services to Ameren and all of its subsidiaries.
The following discussion and analysis should be read in conjunction with the
Notes to Consolidated Financial Statements beginning on page 15, and the
Management's Discussion and Analysis of Financial Condition and Results of
Operations (MD&A), the Audited Consolidated Financial Statements and the Notes
to Consolidated Financial Statements appearing in the Registrant's 2000 Annual
Report to Stockholders (which are incorporated by reference in the Registrant's
2000 Form 10-K).
References to the Registrant 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
Third quarter 2001 earnings of $267 million, or $1.94 per share, increased $11
million, or 7 cents per share, as compared to the third quarter of 2000.
Earnings for the nine months ended September 30, 2001, totaled $420 million, or
$3.06 per share, compared to the year-ago earnings of $431 million or $3.14 per
share. Earnings for the 12 months ended September 30, 2001, were $446 million,
or $3.25 per share, compared to $426 million, or $3.10 per share, for the
preceding 12-month period.
Earnings and earnings per share fluctuated due to many conditions, primarily:
sales growth, weather variations, credits to electric customers, electric rate
reductions, gas rate changes, competitive market forces, fluctuating operating
costs (including Callaway Nuclear Plant refueling outages), expenses relating to
the withdrawal from the electric transmission related Midwest Independent System
Operator (Midwest ISO), charges for coal contract terminations, adoption of a
new accounting standard, changes in interest expense, and changes in income and
property taxes.
The Registrant continues to estimate that ongoing earnings per share for the
year ending December 31, 2001, will range between $3.30 and $3.45 per share.
This estimate continues to incorporate a future form of incentive regulation,
which includes retail electric rate reductions and additional customer credits.
This estimate is subject to, among other things, the regulatory issues
associated with the Registrant's Missouri retail electric operations (see
discussion below under "Rate Matters" and Note 2 under Notes to Consolidated
Financial Statements for further information). The resolution of those issues
could differ materially from the assumptions used in the Registrant's 2001
estimate.
The significant items affecting revenues, costs and earnings during the
three-month, nine-month and 12-month periods ended September 30, 2001 and 2000
are detailed on the following pages.
2
Electric Operations
Electric Operating Revenues Variations for periods ended September 30, 2001
from comparable prior-year periods
- ----------------------------------------------------------------------------------------------------------------
(Millions of Dollars) Three Months Nine Months Twelve Months
------------ ----------- -------------
- ----------------------------------------------------------------------------------------------------------------
Credit to customers $ 20 $ 45 $ 23
Effect of abnormal weather 15 62
98
Growth and other 34 91 117
Interchange sales 184 332 384
EEI sales (22) (53) (67)
- ----------------------------------------------------------------------------------------------------------------
$ 231 $ 477 $ 555
- ----------------------------------------------------------------------------------------------------------------
The $231 million increase in third quarter electric revenues compared to the
year-ago quarter was primarily driven by a 30 percent increase in the total
kilowatthour sales. Weather-sensitive residential and commercial sales increased
2 percent and 6 percent, respectively, due to warmer summer weather and moderate
growth, compared to the prior year. Industrial sales rose 2 percent primarily
due to a new industrial contract effective August 2000. During the period,
interchange sales increased significantly; however, lower electric margins were
realized on these sales due to lower energy prices and less low-cost generation
available for sale, resulting primarily from increased demand from native-load
customers. Revenues were also favorably impacted by a reduction in the estimated
credits to Missouri electric customers (see Note 2 under Notes to Consolidated
Financial Statements for further information).
Electric revenues for the first nine months of 2001 increased $477 million
compared to the prior-year period, primarily due to a 13 percent increase in
total kilowatthour sales. Weather-sensitive residential and commercial sales
increased 5 percent and 8 percent, respectively. Industrial sales rose 11
percent primarily due to a new industrial contract effective August 2000, while
wholesale sales rose 13 percent. Interchange sales also increased 52 percent
during the period, however, lower electric margins were realized on these sales
due to lower energy prices and less low-cost generation available for sale.
These increases were offset in part by a decline in sales at EEI, which resulted
from a decrease in sales under a contract with its major customer. Revenues were
also favorably impacted by a reduction in the estimated credits to Missouri
electric customers (see Note 2 under Notes to Consolidated Financial Statements
for further information).
Electric revenues for the 12 months ended September 30, 2001 increased $555
million compared to the prior 12-month period. The increase in revenues was
primarily driven by a 13 percent increase in total kilowatthour sales.
Interchange sales increased 32 percent, while native sales increased 14 percent.
These increases were partially offset by a decline in sales at EEI.
Fuel and Purchased Power Variations for periods ended September 30, 2001
from comparable prior-year periods
- -----------------------------------------------------------------------------------------------------------------
(Millions of Dollars) Three Months Nine Months Twelve Months
------------ ----------- -------------
- -----------------------------------------------------------------------------------------------------------------
Fuel:
Generation $ 4 $ (4) $ 24
Price 15 29 20
Generation efficiencies and other (4) (7) (10)
Coal contract termination payments - - (52)
Purchased power 213 416 463
EEI (19) (41) (52)
- -----------------------------------------------------------------------------------------------------------------
$ 209 $ 393 $ 393
- -----------------------------------------------------------------------------------------------------------------
Fuel and purchased power costs for the three months ended September 30, 2001
increased $209 million, as compared to the prior-year period primarily due to
increased purchased power, resulting from higher sales volume, and higher fuel
costs.
Fuel and purchased power costs for the nine months ended September 30, 2001
increased $393 million as compared to the prior-year period primarily due to
increased purchased power resulting from higher sales volume, higher fuel costs,
and replacement power resulting from the refueling outage of the Registrant's
Callaway Nuclear Plant, which occurred during the second quarter 2001.
Fuel and purchased power costs for the 12 months ended September 30, 2001
increased $393 million as compared to the prior-year period primarily due to
increased generation and purchased power, resulting from higher sales volume,
higher blended fuel costs, and the refueling outage of the Registrant's Callaway
Nuclear Plant, which occurred in second quarter 2001.
3
Gas Operations
Gas revenues for the nine and 12-month periods ended September 30, 2001
increased $74 million and $138 million, respectively, compared to the year-ago
periods primarily from increased sales and higher costs reflected in the
Registrant's purchased gas adjustment clauses.
Gas costs for the nine and 12-months ended September 30, 2001, increased $65
million and $126 million, respectively, primarily due to higher sales and higher
gas prices.
Other Operating Expenses
Other operating expense variations reflected recurring factors such as growth,
inflation, labor and employee benefit increases, and plant maintenance outages.
Other operating expenses increased $7 million and $48 million for the three and
nine month periods ended September 30, 2001 compared to the prior-year periods
primarily due to higher employee benefit costs in 2001, resulting from changes
in actuarial assumptions and investment performance of employee benefit plans'
assets, and increased professional services. Other operating expenses increased
$164 million for the 12-month period ended September 30, 2001 compared to the
same year-ago period primarily due to the withdrawal from the Midwest ISO (see
discussion below under "Electric Industry Restructuring" for further
information), in addition to higher employee benefit costs, resulting from
changes in actuarial assumptions and investment performance of the employee
benefit plans' assets, and increased professional services.
Maintenance expenses for the nine month period ended September 30, 2001
increased $29 million compared to the prior period due to a refueling outage at
the Callaway Nuclear Plant during second quarter 2001. The spring 2001 refueling
was completed in 45 days. There was not a refueling in 2000. Maintenance
expenses for the 12 months ended September 30, 2001 increased $14 million
primarily resulting from an increase in the spring 2001 Callaway Nuclear Plant
refueling expense compared to fall 1999, partially offset by a reduction in
fossil power plant maintenance.
Depreciation and amortization expenses for the three month, nine month and 12
month periods ended September 30, 2001 increased $7 million, $20 million and $36
million, respectively, compared to the prior periods due to increased
depreciable property, primarily resulting from the addition of combustion
turbine generating facilities (see discussion below under "Liquidity and Capital
Resources" for further information).
Taxes
Income taxes increased $12 million and $14 million for the three and 12 months
ended September 30, 2001, respectively, primarily due to higher pretax income.
Other tax expense increased $7 million for the 12 months ended September 30,
2001 compared to the prior year primarily due to a change in the property tax
assessment in the state of Illinois.
Other Income and Deductions
The variation in other income and deductions, net for the three month period
ended September 30, 2001 compared to the prior-year period was primarily due to
contributions in aid of construction as well as gains on the sales of
unregulated property.
The variation in other income and deductions, net for the nine and twelve month
periods ended September 30, 2001 compared to the prior-year periods was
primarily due to gains on the sales of unregulated property and prior period
write-offs of certain nonregulated investments.
Balance Sheet
The 8 percent, or $40 million, increase in trade accounts receivable at
September 30, 2001, compared to the year-end, was due primarily to higher
revenues in August and September 2001 compared to November and December 2000.
Changes in accounts and wages payable and taxes accrued resulted from the timing
of various payments to taxing authorities and suppliers.
Decrease in other current liabilities of $44 million during 2001 is primarily
due to the reduction in the estimated credit that the Registrant expects to pay
its Missouri electric customers (see Note 2 under Notes to Consolidated
Financial Statements for further information).
4
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $735 million for the nine months
ended September 30, 2001, compared to $762 million during the same 2000 period.
Cash flows used in investing activities totaled $813 million and $633 million
for the nine months ended September 30, 2001 and 2000, respectively.
Construction expenditures for the nine months ended September 30, 2001, for
constructing new or improving existing facilities were $812 million, which
included expenditures associated with the purchase of combustion turbine
generating facilities. The Registrant added 670 megawatts of combustion turbine
generation capacity during the nine months ended September 30, 2001. In
addition, the Registrant expended $15 million for the acquisition of nuclear
fuel.
As of September 30, 2001, the Registrant plans to add combustion turbine
generating units as follows: 820 megawatts in 2001 at Resources Company
(including those already in service as of September 30); 710 megawatts in 2002
(470 megawatts at Resources Company and 240 megawatts at AmerenUE); and 325
megawatts each in 2004 and 2005. The Registrant is reviewing four combustion
turbine generating units which had been planned for commercial operation in 2004
and 2005 to determine if they can be used by AmerenUE rather than Resources
Company. The Registrant continually reviews its generation portfolio, and as a
result, could modify its plan for generation asset additions or assignments,
which could include the timing of when certain assets will be added to or
removed from its portfolio, whether the generation will be added to the
regulated or nonregulated portfolio, as well as the type of generation asset
technology that will be employed, among other things.
During the course of the Registrant's resource planning, several alternatives
are being considered to satisfy anticipated regulatory load requirements for
2001 and beyond for AmerenUE, AmerenCIPS and Resources Company. The Registrant
purchased 50 megawatts of capacity and energy during the third quarter of 2001,
and is considering proposals for purchases of up to 500 megawatts of capacity
and energy for the summer of 2002 and beyond, among other things. At this time,
management is unable to predict which course of action it will pursue to satisfy
these requirements and their ultimate impact on the Registrant's financial
position, results of operations or liquidity.
Cash flows provided by financing activities totaled $64 million for the nine
months ended September 30, 2001. The Registrant's principal financing activities
for the period included issuance of short-term and long-term debt, offset by the
redemption of debt and the payment of dividends. On August 24, 2001, the
Registrant's Board of Directors declared a quarterly dividend for the third
quarter of 2001 of 63.5 cents per common share that was paid to shareholders on
September 28, 2001. Common stock dividends paid for the 12 months ended
September 30, 2001, resulted in a payout rate of 78 percent of the Registrant's
earnings to common stockholders.
In April 2001, AmerenCIPS filed with the Securities and Exchange Commission
(SEC) a shelf registration statement on Form S-3 authorizing the offering from
time to time of senior notes in one or more series with an offering price not to
exceed $250 million. The SEC declared the registration statement effective in
May 2001. In June 2001, AmerenCIPS issued $150 million of the senior notes with
an interest rate of 6.625 percent due June 2011. The proceeds of these senior
notes were used to repay short-term debt and first mortgage bonds which matured
in June 2001.
On November 1, 2000, Generating Company issued transfer restricted Senior Notes
in a private placement, Series A due 2005 (Series A Notes) and Senior Notes,
Series B due 2010 (Series B Notes) (collectively, the Senior Notes). Generating
Company filed a registration statement in the first quarter of 2001 to register
the Senior Notes under the Securities Act of 1933, as amended, to permit an
exchange offer of the Senior Notes. The registration statement was declared
effective in April 2001. On June 12, 2001, all holders completed their exchange
of the Senior Notes for new Series C and D Notes which are identical in all
material respects to the Series A Notes and Series B Notes, respectively, except
that the new series of notes do not contain transfer restrictions and are
registered.
The Registrant anticipates securing $400 to $600 million of long-term financing
in late 2001 or early 2002 which will primarily be used to repay short-term debt
incurred in conjunction with construction of combustion turbine generating
facilities.
The Registrant plans to continue utilizing short-term debt to support normal
operations and other temporary requirements. The Registrant and its subsidiaries
are authorized by the SEC under PUHCA to have up to an aggregate $2.8 billion 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 1 to 45 days). At September
30, 2001, the Registrant had committed bank lines of credit aggregating $161
5
million, all of which was unused and available 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. The Registrant has bank
credit agreements, expiring at various dates between 2001 and 2003, that support
commercial paper programs totaling $763 million, $463 million of which is
available for the Registrant's own use and for the use of its subsidiaries. The
remaining $300 million is available for the use of the Registrant's regulated
subsidiaries. At September 30, 2001, $263 million was available under these bank
credit agreements. The Registrant had $459 million of short-term borrowings at
September 30, 2001.
AmerenUE also has a lease agreement that provides for the financing of nuclear
fuel. At September 30, 2001, the maximum amount that could be financed under the
agreement was $120 million. Cash used in financing activities for the nine
months ended September 30, 2001, included redemptions under the lease for
nuclear fuel of $64 million, partially offset by $3 million of issuances. At
September 30, 2001, $53 million was financed under the lease.
The Registrant, in the ordinary course of business, explores opportunities to
reduce its costs in order to remain competitive in the marketplace. Areas where
the Registrant focuses its review include, but are not limited to, labor costs
and fuel supply costs. In the labor area, over the past two years, the
Registrant has reached agreements with all of its major collective bargaining
units which will permit the Registrant to manage its labor costs and practices
effectively in the future. The Registrant also explores alternatives to
effectively manage the size of its workforce. These alternatives include
utilizing hiring freezes, outsourcing and offering employee separation packages.
In the fuel supply area, the Registrant explores alternatives to effectively
manage its overall fuel costs. These alternatives include diversifying fuel
sources for use at the Registrant's fossil power plants (e.g. utilizing low
sulfur versus high sulfur coal), as well as restructuring or terminating
existing contracts with suppliers.
Certain of these cost reduction alternatives could result in additional
investments being made at the Registrant's power plants in order to utilize
different types of coal, or could require nonrecurring payments of employee
separation benefits or nonrecurring payments to restructure or terminate an
existing fuel contract with a supplier. Management is unable to predict which
(if any), and to what extent, these alternatives to reduce its overall cost
structure will be executed, as well as determine the impact of these actions on
the Registrant's future financial position, results of operations or liquidity.
RATE MATTERS
On June 30, 2001, the Registrant's experimental alternative regulation plan (the
Plan) for its Missouri electric customers expired (see Note 2 under Notes to
Consolidated Financial Statements for further information about the Plan). With
the Plan's expiration, on July 2, 2001, the Missouri Public Service Commission
(MoPSC) staff filed with the MoPSC an excess earnings complaint against the
Registrant that proposes to reduce the Registrant's annual electric revenues
ranging from $213 million to $250 million. Factors contributing to the MoPSC
staff's recommendation include return on equity (ROE), revenues and customer
growth, depreciation rates and other cost of service expenses. The ROE
incorporated into the MoPSC staff's recommendation ranges from 9.04 percent to
10.04 percent. The MoPSC has not yet determined a schedule for evidentiary
hearings on the MoPSC staff's recommendation. The MoPSC is not bound by the
MoPSC staff's recommendation. Depending on the outcome of the MoPSC's decision,
further appeals in the courts may be warranted.
In the interim, the Registrant is preparing to vigorously contest the MoPSC
staff's recommendation and expects to continue negotiations with all pertinent
parties with the intent to continue with an incentive regulation plan, similar
in form to the Plan. The Registrant can not predict the outcome of these
negotiations and their impact on the Registrant's financial position, results of
operations or liquidity; however, the impact could be material.
See Note 2 under Notes to Consolidated Financial Statements for further
discussion of Rate Matters.
ELECTRIC INDUSTRY RESTRUCTURING
Certain states are considering proposals or have adopted legislation that will
promote competition at the retail level. During 2000 and in early 2001,
deregulation laws established in the state of California, coupled with high
energy prices, increasing demands for power by users in that state, transmission
constraints, and limited generation resources, among other things, negatively
impacted several major electric utilities in that state. Federal and state
regulators and legislators have proposed and implemented, in part, different
courses of action to attempt to address these issues. The Registrant does not
maintain utility operations in the state of California, nor does it provide
energy directly to utilities in that state. At this time, the Registrant is
uncertain what impact, if any, changes in deregulation laws will have on future
federal and state deregulation laws (including the state of Missouri), which
could directly impact the Registrant's future financial position, results of
operations or liquidity.
6
Illinois
In December 1997, the Governor of Illinois signed the Electric Service Customer
Choice and Rate Relief Law of 1997 (the Law) providing for electric utility
restructuring in Illinois. This legislation introduces competition into the
supply of electric energy in Illinois.
One of the major provisions of the Law is the phasing-in through 2002 of retail
direct access, which allows customers to choose their electric generation
supplier. The phase-in of retail direct access began on October 1, 1999, with
large commercial and industrial customers principally comprising the initial
group. The remaining commercial and industrial customers in Illinois were
offered choice on December 31, 2000. Commercial and industrial customers in
Illinois represent approximately 13 percent of the Registrant's total sales. As
of September 30, 2001, the impact of retail direct access on the Registrant's
financial condition, results of operations, or liquidity was immaterial. Retail
direct access will be offered to residential customers on May 1, 2002.
Missouri
During the legislative session that ended in May 2001, the Registrant
participated in discussions with the Missouri legislature regarding legislation
that would not restructure the electric industry in Missouri, but would allow
utilities to transfer generation assets to an affiliated generating company. In
addition, the legislation would have allowed the State's largest nonresidential
customers to choose their electric supplier, among other things. Electric
industry legislation was not passed during the legislative session.
Midwest ISO and Alliance RTO
In the fourth quarter of 2000, the Registrant announced its intention to
withdraw from the Midwest ISO and to join the Alliance Regional Transmission
Organization (Alliance RTO), and recorded a pretax charge to earnings of $25
million ($15 million after taxes, or 11 cents per share), which related to the
Registrant's estimated obligation under the Midwest ISO agreement for costs
incurred by the Midwest ISO, plus estimated exit costs. During first quarter
2001, the Federal Energy Regulatory Commission (FERC) conditionally approved the
formation, including the rate structure, of the Alliance RTO, and the Registrant
announced that it had signed an agreement to join the Alliance RTO. Also in
first quarter 2001, in a proceeding before the FERC, the Alliance RTO and the
Midwest ISO reached an agreement that would enable Ameren to withdraw from the
Midwest ISO and to join the Alliance RTO. During the second quarter of 2001,
this settlement agreement was approved by the FERC. The Registrant's withdrawal
from the Midwest ISO remains subject to MoPSC approval. Additional regulatory
approvals of the SEC, FERC, MoPSC and the Illinois Commerce Commission may be
required in connection with various transactions involving the Alliance RTO
relating to its organization, capitalization and the possible transfer of
transmission assets. Such approvals, if required, will be sought at the
appropriate times. The Alliance RTO is expected to be operational within 90-120
days after the FERC's approval. At this time, the Registrant is unable to
determine the impact that its withdrawal from the Midwest ISO and its
participation in the Alliance RTO will have on its future financial condition,
results of operations or liquidity.
ACCOUNTING MATTERS
In January 2001, the Registrant implemented Statement of Financial Accounting
Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging
Activities." The impact of that adoption resulted in the Registrant recording a
cumulative effect charge of $7 million after taxes to the income statement, and
a cumulative adjustment of $11 million after income taxes to other comprehensive
income (OCI), which reduced stockholders' equity. (See Note 3 under Notes to
Consolidated Financial Statements for further information.) In June 2001, the
Derivatives Implementation Group (DIG), a committee of the Financial Accounting
Standards Board (FASB) responsible for providing guidance on the implementation
of SFAS 133, reached a conclusion regarding the appropriate accounting treatment
of certain types of energy contracts under SFAS 133. Specifically, the DIG
concluded that power purchase or sales agreements (both forward contracts and
option contracts) may meet an exception for normal purchases and sales
accounting treatment if certain criteria are met. This guidance was effective
beginning July 1, 2001 and did not have a material impact on the Registrant's
financial condition, results of operations or liquidity upon adoption. However,
in October 2001, the DIG revised this guidance, with the revisions effective
January 1, 2002. At this time, the Registrant is evaluating the impact of the
DIG's revisions to determine the effect on the Registrant's future financial
condition, results of operations, or liquidity upon application.
In September 2001, the DIG issued guidance regarding the accounting treatment
for fuel contracts that combine a forward contract and a purchased option
contract. The DIG concluded that contracts containing both a forward contract
and a purchased option contract are not eligible to qualify for the normal
purchases and sales exception under SFAS 133. This guidance is effective in
second quarter 2002. The Registrant is evaluating the impact of this guidance on
its future financial condition, results of operations or liquidity; however, the
impact could be material.
7
In July 2001, the FASB issued SFAS No. 141, "Business Combinations," SFAS 142,
"Goodwill and Other Intangible Assets," and SFAS 143, "Accounting for Asset
Retirement Obligations." SFAS 141 requires business combinations to be accounted
for under the purchase method of accounting, which requires one party in the
transaction to be identified as the acquiring enterprise and for that party to
record the assets and liabilities of the acquired enterprise at fair market
value rather than historical cost. It prohibits use of the pooling-of-interests
method of accounting for business combinations. SFAS 141 is effective for all
business combinations initiated after June 30, 2001, or transactions completed
using the purchase method after June 30, 2001. SFAS 142 requires goodwill
recorded in the financial statements to be tested for impairment at least
annually, rather than amortized over a fixed period, with impairment losses
recorded in the income statement. SFAS 142 is effective for all fiscal years
beginning after December 15, 2001. SFAS 143 requires an entity to record a
liability and corresponding asset representing the present value of legal
obligations associated with the retirement of tangible, long-lived assets. SFAS
143 is effective for fiscal years beginning after June 15, 2002. SFAS 141 and
SFAS 142 are not expected to have a material effect on the Registrant's
financial position, results of operations or liquidity upon adoption. At this
time, the Registrant is assessing the impact of SFAS 143 on its financial
position, results of operations or liquidity upon adoption.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Market risk represents the risk of changes in value of a physical asset or a
financial instrument, derivative or non-derivative, caused by fluctuations in
market variables (e.g., interest rates, equity prices, commodity prices, etc.).
The following discussion of the Registrant's risk management activities includes
"forward-looking" statements that involve risks and uncertainties. Actual
results could differ materially from those projected in the "forward-looking"
statements. The Registrant handles market risks in accordance with established
policies, which may include entering into various derivative transactions. In
the normal course of business, the Registrant also faces risks that are either
non-financial or non-quantifiable. Such risks principally include business,
legal, operational and credit risk and are not represented in the following
analysis.
The Registrant's risk management objective is to optimize its physical
generating assets within prudent risk parameters. Risk management policies are
set by a Risk Management Steering Committee, which is comprised of senior-level
Ameren officers.
Interest Rate Risk
The Registrant is exposed to market risk through changes in interest rates
associated with its issuance of both long-term and short-term variable-rate debt
and fixed-rate debt, commercial paper and auction-rate preferred stock. The
Registrant manages its interest rate exposure by controlling the amount of these
instruments it holds within its total capitalization portfolio and by monitoring
the effects of market changes in interest rates.
If interest rates increase one percentage point in 2002, as compared to 2001,
the Registrant's interest expense would increase by approximately $11 million
and net income would decrease by approximately $7 million. This amount has been
determined using the assumptions that the Registrant's outstanding variable-rate
debt, commercial paper and auction-rate preferred stock, as of September 30,
2001, continued to be outstanding throughout 2002, and that the average interest
rates for these instruments increased one percentage point over 2001. The
estimate does not consider the effects of the reduced level of potential overall
economic activity that would exist in such an environment. In the event of a
significant change in interest rates, management would likely take actions to
further mitigate its exposure to this market risk. However, due to the
uncertainty of the specific actions that would be taken and their possible
effects, the sensitivity analysis assumes no change in the Registrant's
financial structure.
Commodity Price Risk
The Registrant is exposed to changes in market prices for natural gas, fuel and
electricity. Several techniques are utilized to mitigate the Registrant's risk,
including utilizing derivative financial instruments. A derivative is a contract
that has its value dependent on, or derived from, the value of some underlying
asset. The derivative financial instruments that the Registrant uses (primarily
forward contracts, futures contracts and option contracts) are dictated by risk
management policies.
With regard to its natural gas utility business, the Registrant's exposure to
changing market prices is in large part mitigated by the fact that the
Registrant has purchased gas adjustment clauses (PGAs) in place in both its
Missouri and Illinois jurisdictions. The PGA allows the Registrant to pass on to
its customers its prudently incurred costs of natural gas.
The Registrant has a subsidiary, AmerenEnergy Fuels and Services Company, a
wholly owned subsidiary of Resources Company, which is responsible for providing
fuel procurement and gas supply services on behalf of the Registrant's operating
subsidiaries, and for managing fuel and natural gas price risks. Fixed price
8
forward contracts, as well as futures and options, are all instruments, which
may be used to manage these risks. The majority of the Registrant's fuel supply
contracts are physical forward contracts. Since the Registrant does not have a
provision similar to the PGA for its electric operations, the Registrant has
entered into several long-term contracts with various suppliers to purchase coal
and nuclear fuel to manage its exposure to fuel prices. All of the required coal
for the Registrant's coal plants has been acquired at fixed prices for 2001. In
addition, at least 80 percent of the coal requirements through 2005 are covered
by long-term contracts. The Registrant has recently experienced some delays in
its coal deliveries due to certain transportation and operating constraints in
the system. The Registrant is working closely with the transportation companies
and monitoring its operating practices in order to maintain adequate levels of
coal inventory for future operating purposes. With regard to the Registrant's
nonregulated electric generation operations, the Registrant is exposed to
changes in market prices for natural gas to the extent it must purchase natural
gas to run its combustion turbine generators. The Registrant's natural gas
procurement strategy is designed to ensure reliable and immediate delivery of
natural gas to its intermediate and peaking units by optimizing transportation
and storage options and minimizing cost and price risk by structuring various
supply agreements to maintain access to multiple gas pools and supply basins and
reducing the impact of price volatility.
With regard to the Registrant's exposure to commodity price risk for purchased
power and excess electricity sales, the Registrant has a subsidiary,
AmerenEnergy, which has as its primary responsibility managing market risks
associated with changing market prices for electricity purchased and sold on
behalf of AmerenUE and Generating Company.
Although the Registrant cannot completely eliminate the effects of gas price
volatility, its strategy is designed to minimize the effect of market conditions
on the results of operations. The Registrant's gas procurement strategy includes
procuring natural gas under a portfolio of agreements with price structures,
including fixed price, indexed price and embedded price hedges such as caps and
collars. The Registrant's strategy also utilizes physical assets through
storage, operator and balancing agreements to minimize price volatility. The
Registrant's electric marketing strategy is to extract additional value from its
generation facilities by selling energy in excess of needs for term sales and
purchasing energy when the market price is less than the cost of generation. The
Registrant's primary use of derivatives has been limited to transactions that
are expected to reduce price risk exposure for the Registrant.
Equity Price Risk
The Registrant maintains trust funds, as required by the Nuclear Regulatory
Commission and Missouri and Illinois state laws, to fund certain costs of
nuclear decommissioning. As of September 30, 2001, these funds were invested
primarily in domestic equity securities, fixed-rate, fixed-income securities,
and cash and cash equivalents. By maintaining a portfolio that includes
long-term equity investments, the Registrant is seeking to maximize the returns
to be utilized to fund nuclear decommissioning costs. However, the equity
securities included in the Registrant's portfolio are exposed to price
fluctuations in equity markets, and the fixed-rate, fixed-income securities are
exposed to changes in interest rates. The Registrant actively monitors its
portfolio by benchmarking the performance of its investments against certain
indices and by maintaining, and periodically reviewing, established target
allocation percentages of the assets of its trusts to various investment
options. The Registrant's exposure to equity price market risk is, in large
part, mitigated due to the fact that the Registrant is currently allowed to
recover its decommissioning costs in its electric rates.
SAFE HARBOR STATEMENT
Statements made in this Form 10-Q 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, events, conditions, and
financial performance. In connection with the "Safe Harbor" provisions of the
Private Securities Litigation Reform Act of 1995, the Registrant is providing
this cautionary statement to identify important factors that could cause actual
results to differ materially from those anticipated. The following factors, in
addition to those discussed elsewhere in this report and in the 2000 Annual
Report to Stockholders (portions of which are incorporated by reference in the
Registrant's 2000 Form 10-K) and in subsequent securities filings, could cause
results to differ materially from management expectations as suggested by such
"forward-looking" statements: the effects of regulatory actions, including
changes in regulatory policy; changes in laws and other governmental actions;
the impact on the Registrant of current regulations related to the phasing-in of
the opportunity for some customers to choose alternative energy suppliers in
Illinois; the effects of increased competition in the future, due to, among
other things, deregulation of certain aspects of the Registrant's business at
both the state and federal levels; the effects of withdrawal from the Midwest
ISO and membership in the Alliance RTO; future market prices for fuel and
purchased power, electricity, and natural gas, including the use of financial
instruments; average rates for electricity in the Midwest; business and economic
conditions; the impact of the adoption of new accounting standards; interest
rates; weather conditions; fuel availability; generation plant construction,
installation and performance; the impact of current environmental regulations on
utilities and generating companies and the expectation that more stringent
9
requirements will be introduced over time, which could potentially have a
negative financial effect; monetary and fiscal policies; future wages and
employee benefits costs; competition from other generating facilities including
new facilities that may be developed in the future; cost and availability of
transmission capacity for the energy generated by the Registrant's generating
facilities or required to satisfy energy sales made by the Registrant; and legal
and administrative proceedings.
10
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
UNAUDITED
(Thousands of Dollars, Except Shares)
September 30, December 31,
ASSETS 2001 2000
- ------ ------------- -------------
Property and plant, at original cost:
Electric $ 13,316,855 $ 12,684,366
Gas 527,071 509,746
Other 104,495 97,214
------------- ------------
13,948,421 13,291,326
Less accumulated depreciation and amortization 6,454,929 6,204,367
------------- ------------
7,493,492 7,086,959
Construction work in progress:
Nuclear fuel in process 87,171 117,789
Other 644,734 500,924
------------- ------------
Total property and plant, net 8,225,397 7,705,672
------------- ------------
Investments and other assets:
Investments 40,187 40,235
Nuclear decommissioning trust fund 174,478 190,625
Other 99,367 97,630
------------- ------------
Total investments and other assets 314,032 328,490
------------- ------------
Current assets:
Cash and cash equivalents 112,112 125,968
Accounts receivable - trade (less allowance for doubtful
accounts of $8,786 and $8,028, respectively) 514,105 474,425
Other accounts and notes receivable 45,081 56,529
Materials and supplies, at average cost -
Fossil fuel 155,955 107,572
Other 120,676 119,478
Other current assets 35,152 37,210
------------- -------------
Total current assets 983,081 921,182
------------- -------------
Regulatory assets:
Deferred income taxes 602,414 600,100
Other 153,012 158,986
------------- ------------
Total regulatory assets 755,426 759,086
------------- ------------
Total Assets $ 10,277,936 $ 9,714,430
============= ============
CAPITAL AND LIABILITIES
Capitalization:
Common stock, $.01 par value, 400,000,000 shares authorized -
137,539,177 shares outstanding $ 1,375 $ 1,372
Other paid-in capital, principally premium on
common stock 1,593,098 1,581,339
Retained earnings 1,772,113 1,613,960
Accumulated other comprehensive income (4,755) -
Other (5,117) -
------------- ------------
Total common stockholders' equity 3,356,714 3,196,671
Preferred stock not subject to mandatory redemption 235,197 235,197
Long-term debt 2,811,148 2,745,068
------------- ------------
Total capitalization 6,403,059 6,176,936
============= ============
Minority interest in consolidated subsidiaries 3,534 3,940
Current liabilities:
Current maturity of long-term debt 47,444 44,444
Short-term debt 459,091 203,260
Accounts and wages payable 287,060 462,924
Accumulated deferred income taxes 46,139 49,829
Taxes accrued 390,464 124,706
Other 256,331 300,798
------------- ------------
Total current liabilities 1,486,529 1,185,961
------------- ------------
Accumulated deferred income taxes 1,562,689 1,540,536
Accumulated deferred investment tax credits 160,101 164,120
Regulatory liability 175,573 183,541
Other deferred credits and liabilities 486,451 459,396
------------- ------------
Total Capital and Liabilities $ 10,277,936 $ 9,714,430
============= ============
See Notes to Consolidated Financial Statements.
11
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
UNAUDITED
(Thousands of Dollars, Except Shares and Per Share Amounts)
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
-------------------- -------------------- --------------------
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
OPERATING REVENUES:
Electric $ 1,389,991 $1,158,509 $3,251,374 $2,774,763 $4,003,189 $3,447,780
Gas 40,517 36,275 255,343 181,447 397,782 248,145
Other 1,105 939 6,440 5,597 7,209 6,484
----------- ---------- ---------- ---------- ---------- ----------
Total operating revenues 1,431,613 1,195,723 3,513,157 2,961,807 4,408,180 3,702,409
OPERATING EXPENSES:
Operations
Fuel and purchased power 493,814 285,157 1,163,265 770,259 1,418,227 1,025,043
Gas 19,967 23,632 171,429 106,549 274,347 148,158
Other 173,273 166,008 517,880 469,654 712,770 615,475
----------- ---------- ---------- ---------- ---------- ----------
687,054 474,797 1,852,574 1,346,462 2,405,344 1,788,676
Maintenance 78,216 79,155 296,233 267,653 396,501 386,411
Depreciation and amortization 104,226 96,845 303,400 283,808 402,702 373,784
Income taxes 176,065 163,706 286,125 287,196 300,121 286,070
Other taxes 75,630 75,535 203,114 203,219 264,960 258,376
----------- ---------- ---------- ---------- ---------- ----------
Total operating expenses 1,121,191 890,038 2,941,446 2,388,338 3,769,628 3,093,317
OPERATING INCOME 310,422 305,685 571,711 573,469 638,552 609,092
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used
during construction 4,137 1,250 7,959 4,079 9,178 5,211
Miscellaneous, net 3,615 (5,481) (867) (13,481) 8,214 (17,576)
----------- ---------- ---------- ----------- ---------- ----------
Total other income and (deductions) 7,752 (4,231) 7,092 (9,402) 17,392 (12,365)
----------- ---------- ---------- ----------- ---------- -----------
INCOME BEFORE INTEREST CHARGES
AND PREFERRED DIVIDENDS 318,174 301,454 578,803 564,067 655,944 596,727
INTEREST CHARGES AND PREFERRED
DIVIDENDS:
Interest 50,498 44,223 148,836 129,411 199,131 166,242
Allowance for borrowed funds used
during construction (2,006) (2,136) (5,963) (5,928) (8,327) (7,692)
Preferred dividends of subsidiaries 3,106 3,230 9,391 9,469 12,622 12,664
---------- ---------- ---------- ----------- ---------- ----------
Net interest charges and 51,598 45,317 152,264 132,952 203,426 171,214
preferred dividends ----------- ---------- ---------- ----------- ----------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 266,576 256,137 426,539 431,115 452,518 425,513
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE, NET OF
INCOME TAXES -- -- (6,841) -- (6,841) --
----------- ---------- ---------- ----------- ----------- ----------
NET INCOME $266,576 $256,137 $419,698 $431,115 $445,677 $425,513
=========== ========== ========== =========== ========== ==========
EARNINGS PER COMMON SHARE - BASIC AND DILUTED
(Based on average shares outstanding):
Income before cumulative effect of change $1.94 $1.87 $3.11 $3.14 $3.30 $3.10
in accounting principle
Cumulative effect of change in accounting
principle, net of income taxes -- -- (0.05) -- (0.05) --
Net income ----------- ------------ ----------- ------------ ------------ ---------
$1.94 $1.87 $3.06 $3.14 $3.25 $3.10
=========== ============ =========== ============ ============ =========
AVERAGE COMMON SHARES OUTSTANDING 137,222,499 137,215,462 137,217,834 137,215,462 137,217,236 137,215,462
=========== ============= ============ ============ ============ =========
See Notes to Consolidated Financial Statements.
12
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
UNAUDITED
(Thousands of Dollars)
Nine Months Ended
September 30,
-----------------------
2001 2000
---- ----
Cash Flows From Operating:
Net income $ 419,698 $ 431,115
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting 6,841 --
principle
Depreciation and amortization 293,911 274,557
Amortization of nuclear fuel 21,084 27,714
Allowance for funds used during construction (13,922) (10,007)
Deferred income taxes, net 13,645 11,976
Deferred investment tax credits, net (4,019) (4,501)
Changes in assets and liabilities:
Receivables, net (28,232) (88,251)
Materials and supplies (49,581) 3,898
Accounts and wages payable (175,864) (86,295)
Taxes accrued 265,758 170,049
Other, net (14,324) 31,665
--------- ---------
Net cash provided by operating activities 734,995 761,920
Cash Flows From Investing:
Construction expenditures (812,109) (657,622)
Allowance for funds used during construction 13,922 10,007
Nuclear fuel expenditures (14,988) (11,691)
Other 48 26,314
--------- ---------
Net cash used in investing activities (813,127) (632,992)
Cash Flows From Financing:
Dividends on common stock (261,395) (261,395)
Redemptions:
Nuclear fuel lease (64,122) (8,276)
Long-term debt (30,000) (425,650)
Issuances:
Nuclear fuel lease 3,062 7,270
Short-term debt 255,831 324,178
Long-term debt 160,900 277,600
--------- ---------
Net cash provided by (used in) financing activities 64,276 (86,273)
--------- ---------
Net change in cash and cash equivalents (13,856) 42,655
Cash and cash equivalents at beginning of year 125,968 194,882
--------- ---------
Cash and cash equivalents at end of period $ 112,112 $ 237,537
========= =========
Cash paid during the periods:
Interest (net of amount capitalized) $ 122,852 $ 118,111
Income taxes, net $ 78,364 $ 157,399
See Notes to Consolidated Financial Statements.
13
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS' EQUITY
UNAUDITED
(Thousands of Dollars)
Nine Months Ended Year Ended
September 30, 2001 December 31, 2000
--------------------- ------------------
Common stock
Beginning balance $ 1,372 $ 1,372
Shares issued 3 --
----------- -----------
1,375 1,372
Other paid-in capital
Beginning balance 1,581,339 1,582,501
Shares issued 12,217 --
Employee stock awards (458) (1,162)
----------- -----------
1,593,098 1,581,339
Retained earnings
Beginning balance 1,613,960 1,505,827
Net income 419,698 457,094
Dividends (261,545) (348,961)
----------- -----------
1,772,113 1,613,960
Accumulated other comprehensive income
Beginning balance -- --
Change in current period (4,755) --
----------- ------------
(4,755) --
Other
Beginning balance -- --
Unamortized restricted stock compensation (5,704) --
Compensation amortized 587 --
----------- -----------
(5,117) --
----------- -----------
Total common stockholders' equity $ 3,356,714 $ 3,196,671
=========== ===========
Comprehensive income, net of tax
Net income $ 419,698 $ 457,094
Cumulative effect of accounting change, (11,258) --
net of taxes
Unrealized net gain on derivative
hedging instruments 6,503 --
----------- -----------
$ 414,943 $ 457,094
=========== ===========
See Notes to Consolidated Financial Statements.
14
AMEREN CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
September 30, 2001
Note 1 - Summary of Significant Accounting Policies
Basis of Presentation
Ameren Corporation (Ameren or the Registrant) is a holding company registered
under the Public Utility Holding Company Act of 1935 (PUHCA). Ameren's primary
operating companies are Union Electric Company (AmerenUE), Central Illinois
Public Service Company (AmerenCIPS), both subsidiaries of Ameren, and
AmerenEnergy Generating Company (Generating Company), the nonregulated electric
generating subsidiary of AmerenEnergy Resources Company (Resources Company),
which is a subsidiary of Ameren. Ameren also has a 60 percent ownership interest
in Electric Energy, Inc. (EEI). EEI owns and/or operates electric generation and
transmission facilities in Illinois that supply electric power primarily to a
uranium enrichment plant located in Paducah, Kentucky. That interest is
consolidated for financial reporting purposes. Ameren's other subsidiaries
include AmerenEnergy, Inc. (AmerenEnergy), Ameren Development Company, Ameren
Services Company and CIPSCO Investment Company. AmerenEnergy, an energy
marketing subsidiary, primarily serves as a power marketing agent for AmerenUE
and Generating Company and provides a range of energy and risk management
services to targeted customers. Ameren Development Company is a nonregulated
subsidiary encompassing Ameren's nonregulated products and services. Resources
Company holds the Registrant's nonregulated generating operations. Ameren
Services Company provides shared support services to Ameren and all of its
subsidiaries.
The accompanying financial statements include the accounts of Ameren and its
consolidated subsidiaries (collectively the Registrant). All subsidiaries for
which the Registrant owns directly or indirectly more than 50 percent of the
voting stock are included as consolidated subsidiaries. Ameren's primary
operating companies, AmerenUE, AmerenCIPS and Generating Company, are engaged
principally in the generation, transmission, distribution and sale of electric
energy and the purchase, distribution, transportation and sale of natural gas.
The operating companies serve 1.5 million electric and 300,000 natural gas
customers in a 44,500-square-mile area of Missouri and Illinois. All significant
intercompany balances and transactions have been eliminated from the
consolidated financial statements.
Interim Financial Statements
Financial statement note disclosures, normally included in consolidated
financial statements prepared in conformity with generally accepted accounting
principles, have been omitted in this Form 10-Q pursuant to the Rules and
Regulations of the Securities and Exchange Commission. However, in the opinion
of the Registrant, the disclosures contained in this Form 10-Q are adequate to
make the information presented not misleading. See Notes to Consolidated
Financial Statements included in the 2000 Annual Report to Stockholders (which
are incorporated by reference in the Registrant's 2000 Form 10-K) for
information relevant to the consolidated financial statements contained in this
Form 10-Q, including information as to the significant accounting policies of
the Registrant.
In the opinion of the Registrant, the interim financial statements filed as part
of this Form 10-Q reflect all adjustments, consisting only of normal recurring
adjustments, necessary for a fair statement of the results for the periods
presented.
Factors Affecting Business
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, 2001 and 2000, are not necessarily indicative of trends for any three-month,
nine-month or twelve-month period.
Note 2 - Regulatory Matters
Missouri
In July 1995, the Missouri Public Service Commission (MoPSC) approved an
agreement establishing contractual obligations involving the Registrant's
Missouri retail electric rates. Included was a three-year experimental
alternative regulation plan (the Original Plan) that ran from July 1, 1995
through June 30, 1998, which provided that earnings in those years in excess of
a 12.61 percent regulatory return on equity be shared equally between customers
and stockholders, and earnings above a 14 percent regulatory return on equity be
credited to customers. The formula for computing the credit used twelve-month
results ending June 30, rather than calendar year earnings.
15
A new three-year experimental alternative regulation plan (the New Plan) was
included in the joint agreement authorized by the MoPSC in its February 1997
order approving the merger of AmerenUE and CIPSCO Incorporated that formed
Ameren. Like the Original Plan, the New Plan required that earnings over a 12.61
percent regulatory return on equity up to a 14 percent regulatory return on
equity be shared equally between customers and stockholders. The New Plan also
returned to customers 90 percent of all earnings above a 14 percent regulatory
return on equity up to a 16 percent regulatory return on equity. Earnings above
a 16 percent regulatory return on equity were credited entirely to customers.
The New Plan ran from July 1, 1998 through June 30, 2001. As of September 30,
2001, the Registrant recorded an estimated credit of $40 million, or 17 cents
per share, for the plan year ended June 30, 2001 compared to $35 million, or 15
cents per share, in the prior period. These credits were reflected as a
reduction in electric revenues in the periods accrued. The final amount of the
credit will depend on several factors, including the Registrant's earnings for
12 months ended June 30, 2001.
With the New Plan's expiration on June 30, 2001, on July 2, 2001, the MoPSC
staff filed with the MoPSC an excess earnings complaint against the Registrant
that proposes to reduce the Registrant's annual electric revenues ranging from
$213 million to $250 million. Factors contributing to the MoPSC staff's
recommendation include return on equity (ROE), revenues and customer growth,
depreciation rates and other cost of service expenses. The ROE incorporated into
the MoPSC staff's recommendation ranges from 9.04 percent to 10.04 percent. The
MoPSC has not yet determined a schedule for evdentiary hearings on the MoPSC
staff's recommendation. The MoPSC is not bound by the MoPSC staff's
recommendation. Depending on the outcome of the MoPSC's decision, further
appeals in the courts may be warranted.
In the interim, the Registrant is preparing to vigorously contest the MoPSC
staff's recommendation and expects to continue negotiations with all pertinent
parties with the intent to continue with an incentive regulation plan, similar
to the New Plan. The Registrant can not predict the outcome of these
negotiations and their impact on the Registrant's financial position, results of
operations or liquidity; however, the impact could be material.
Midwest ISO and Alliance RTO
In the fourth quarter of 2000, the Registrant announced its intention to
withdraw from the Midwest Independent System Operator (Midwest ISO) and to join
the Alliance Regional Transmission Organization (Alliance RTO), and recorded a
pretax charge to earnings of $25 million ($15 million after taxes, or 11 cents
per share), which related to the Registrant's estimated obligation under the
Midwest ISO agreement for costs incurred by the Midwest ISO, plus estimated exit
costs. During first quarter 2001, the Federal Energy Regulatory Commission
(FERC) conditionally approved the formation, including the rate structure, of
the Alliance RTO, and the Registrant announced that it had signed an agreement
to join the Alliance RTO. Also in first quarter 2001, in a proceeding before the
FERC, the Alliance RTO and the Midwest ISO reached an agreement that would
enable Ameren to withdraw from the Midwest ISO and to join the Alliance RTO.
During the second quarter of 2001, this settlement agreement was approved by the
FERC. The Registrant's withdrawal from the Midwest ISO remains subject to MoPSC
approval. Additional regulatory approvals of the FERC, MoPSC, Securities and
Exchange Commission and the Illinois Commerce Commission may be required in
connection with various transactions involving the Alliance RTO relating to its
organization, capitalization and the possible transfer of transmission assets.
Such approvals, if required, will be sought at the appropriate times. The
Alliance RTO is expected to be operational within 90-120 days after the FERC's
approval. At this time, the Registrant is unable to determine the impact that
its withdrawal from the Midwest ISO and its participation in the Alliance RTO
will have on its future financial condition, results of operations or liquidity.
Note 3 - Derivative Financial Instruments
Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for
Derivative Instruments and Hedging Activities" became effective on January 1,
2001. SFAS 133 established accounting and reporting standards for derivative
financial instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities. SFAS 133 requires recognition of
all derivatives as either assets or liabilities on the balance sheet measured at
fair value. The intended use of derivatives and their designation as either a
fair value hedge or a cash flow hedge determines when the gains or losses on the
derivatives are to be reported in earnings and when they are reported as a
component of other comprehensive income (OCI) in stockholders' equity. In
accordance with the transition provisions of SFAS 133, the Registrant recorded a
cumulative effect charge of $7 million after income taxes to the income
statement, comprised of $2 million for ineffective portion of cash flow hedges
and $5 million for discontinued hedges. The Registrant also recorded a
cumulative effect adjustment of $11 million after income taxes, representing the
effective portion of designated cash flow hedges, to OCI, which reduced
16
stockholders' equity. Gains and losses on derivatives that arose prior to the
initial application of SFAS 133 and that were previously deferred as adjustments
of the carrying amount of hedged items were not adjusted and were not included
in the transition adjustments described above.
All derivatives are recognized on the balance sheet at their fair value. On the
date that the Registrant enters into a derivative contract, it designates the
derivative as (1) a hedge of the fair value of a recognized asset or liability
or an unrecognized firm commitment (a "fair value" hedge); (2) a hedge of a
forecasted transaction or the variability of cash flows that are to be received
or paid in connection with a recognized asset or liability (a "cash flow"
hedge); or (3) an instrument that is held for trading or non-hedging purposes (a
"non-hedging" instrument). The Registrant reevaluates its classification of
individual derivative transactions daily. The Registrant designates or
de-designates derivative transactions as hedges based on many factors including
changes in expectations of economic generation availability and changes in
projected sales commitments. Changes in the fair value of derivatives are
captured and reported based on the anticipated use of the derivative. If a
derivative is designated as a cash flow hedge, the effective portion will not be
reflected in the income statement. If the derivative is subsequently designated
as a non-hedging instrument, any further change in fair value will be reflected
in the income statement, with any previously deferred change in fair value
remaining in accumulated OCI until the indicated delivery period. If, on the
other hand, the derivative had been designated as a non-hedging transaction and
subsequently designated as a cash flow hedge, the initial change in fair value
between the transaction date and the hedge designation date will be recorded in
income, and the effective portion of any further change will be deferred in OCI.
Changes in the fair value of derivatives designated as fair value hedges and
changes in the fair value of the hedged asset or liability that are attributable
to the hedged risk (including changes that reflect losses or gains on firm
commitments) are recorded in current-period earnings. Any hedge ineffectiveness
(which represents the amount by which the changes in the fair value of the
derivative exceed the changes in the fair value of the hedged item) is recorded
in current-period earnings. Changes in the fair value of derivative trading and
non-hedging instruments are reported in current-period earnings.
The Registrant utilizes derivatives principally to manage the risk of changes in
market prices for natural gas, fuel, electricity and emission credits. The
Registrant's risk management objective is to optimize the return from its
physical generating assets, while managing exposures to volatile energy
commodity prices and emission allowances within prudent risk management
policies, which are established by a Risk Management Steering Committee (RMSC)
comprised of senior-level Ameren officers. Price fluctuations in natural gas,
fuel and electricity cause (1) an unrealized appreciation or depreciation of the
Registrant's firm commitments to purchase when purchase prices under the firm
commitment are compared with current commodity prices; (2) market values of fuel
and natural gas inventories or purchased power to differ from the cost of those
commodities under the firm commitment; and (3) actual cash outlays for the
purchase of these commodities to differ from anticipated cash outlays. The
derivatives that the Registrant uses to hedge these risks are dictated by risk
management policies and include forward contracts, futures contracts, options
and swaps. Ameren primarily uses derivatives to optimize the value of its
physical and contractual positions. Ameren continually assesses its supply and
delivery commitment positions against forward market prices and internally
forecasts forward prices and modifies its exposure to market, credit and
operational risk by entering into various offsetting transactions. In general
these transactions serve to reduce price risk for the Registrant. Additionally,
the Registrant is authorized to engage in certain transactions that serve to
increase the organization's exposure to price, credit and operational risk for
expected gains. All transactions are continuously monitored and valued by the
RMSC to assure compliance with Ameren policies. The RMSC employs a variety of
risk measurement techniques and position limits including value at risk, credit
value at risk, stress testing, effectiveness testing along with qualitative
measures to establish transaction parameters and measure transaction compliance.
By using derivative financial instruments, the Registrant is exposed to credit
risk and market risk. Credit risk is the risk that the counterparty might fail
to fulfill its performance obligations under contractual terms. Credit risk
management is based upon consideration and measurement of four factors: (1)
accounts receivable; (2) mark to market; (3) probability of default; and (4) the
recovery rate of the defaulted position that is likely to be recovered. The
Registrant manages its credit (or repayment) risk in derivative instruments by
(1) using both portfolio limits, i.e. no more than prescribed dollar amounts
exposed to companies within various credit categories as well as limiting
exposures to individual companies; (2) monitoring the financial condition of its
counterparties; and (3) enhancing credit quality through contractual terms such
as netting, required collateral postings, letters of credit and parental
guaranties.
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Market risk is the risk that the value of a financial instrument might be
adversely affected by a change in commodity prices. The Registrant manages this
risk by establishing and monitoring parameters that limit the types and degree
of market risk that may be undertaken as mentioned above.
The following is a summary of Ameren's risk management strategies and the effect
of these strategies on Ameren's consolidated financial statements.
Cash Flow Hedges
The Registrant routinely enters into forward purchase and sales contracts for
electricity based on forecasted levels of excess economic generation. The amount
of excess economic generation varies throughout the year and is monitored by the
RMSC. The contracts typically cover a period of twelve months or less. The
purpose of these contracts is to hedge against possible price fluctuations in
the spot market for the period covered under the contracts. The Registrant
formally documents all relationships between hedging instruments and hedged
items, as well as its risk-management objective and strategy for undertaking
various hedge transactions. This process includes linking all derivatives
designated as cash flow hedges to specific forecasted transactions. The
Registrant also formally assesses (both at hedge's inception and on an ongoing
basis) whether the derivatives used in hedging transactions have historically
been highly effective in offsetting changes in the cash flows of hedged items
and whether those derivatives are expected to remain highly effective in future
periods.
The Registrant has entered into forward starting interest rate swaps to hedge
the interest rate risk associated with the cost of a future issuance of
fixed-rate debt. Under a forward starting swap, the Registrant agrees to pay or
receive an amount equal to the difference (calculated on a net present value
basis) of the respective cash flows based on the notional amount of the
instrument and the difference between the forward starting swap rate determined
at the date when the agreement is established and the spot swap rate at the date
when the agreement is settled, typically when the Registrant issues the hedged
debt issuance. The notional amounts of the agreement are not exchanged. The
Registrant entered into these swap agreements with major financial institutions
in order to minimize counterparty credit risk. At September 30, 2001, the
Registrant had notional amounts of interest rate swaps hedging the anticipated
debt issuance of $150 million. These agreements, by their current terms, settle
in December 2001.
Interest rate swaps are reflected at fair value in the Registrant's consolidated
balance sheet and the related gains and losses on these agreements are deferred
in shareholders' equity (as a component of other comprehensive income). These
deferred gains and losses are then amortized as an adjustment to interest
expense over the same period in which the related interest costs on the new debt
issuance is recognized in income.
For the three months ended September 30, 2001, the pretax net gain, which
represented the impact of discontinued cash flow hedges, the ineffective portion
of cash flow hedges, as well as the reversal of amounts previously recorded in
the transition adjustment due to transactions going to delivery, was $4 million.
For the nine months ended September 30, 2001, the Registrant recorded a pretax
net gain of $13 million in electric revenues in the statement of income. This
gain represented the impact of discontinued cash flow hedges, the ineffective
portion of cash flow hedges, as well as the reversal of amounts previously
recorded in the transition adjustment due to transactions going to delivery. All
components of each derivative's gain or loss were included in the assessment of
hedge effectiveness.
As of September 30, 2001, all $3 million of the deferred net losses on
derivative instruments accumulated in other comprehensive income are expected to
be reversed during the next twelve months. The derivative losses will be
reversed upon delivery of the commodity being hedged.
Other Derivatives
The Registrant enters into option transactions to manage the Registrant's
positions in sulfur dioxide (SO2) allowances. In addition, the Registrant enters
into option transactions to manage the Registrant's coal purchasing prices and
to manage the cost of electricity by selling puts at prices below the marginal
cost of generation. These transactions are treated as non-hedge transactions
under SFAS 133; therefore, the net change in the market value of SO2 options is
recorded as electric revenues and the net change in the market value of coal
options is recorded as fuel and purchased power in the statement of income.
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Other
As of September 30, 2001, the Registrant has recorded the fair value of
derivative financial instrument assets of $13 million in Other Assets and
derivative financial instrument liabilities of $26 million in Other Investments
and Other Deferred Credits and Liabilities.
The Registrant has entered into fixed-price forward contracts for the purchase
of coal and natural gas. While these contracts meet the definition of a
derivative under SFAS 133, the Registrant records these transactions as normal
purchases and normal sales because the contracts are expected to result in
physical delivery. The Registrant is currently reevaluating the accounting for
these transactions as a result of recent guidance issued by the Derivatives
Implementation Group of the Financial Accounting Standards Board (see Accounting
Matters under Management's Discussion and Analysis of Financial Condition and
Results of Operations for further discussion).
Note 4 - Segment Information
Segment information for the three-month, nine-month and 12-month periods ended
September 30, 2001 and 2000 is as follows:
- ------------------------------------------------------------------------------------------
Regulated Reconciling
(in millions) Utilities All Other Items* Total
- ------------------------------------------------------------------------------------------
Three months ended September 30, 2001:
Revenues $1,629 $ 60 $(257) $1,432
Net Income 267 -- -- 267
- -----------------------------------------------------------------------------------------
Three months ended September 30, 2000:
Revenues $1,295 $ 88 $(187) $1,196
Net Income 255 1 -- 256
- -----------------------------------------------------------------------------------------
Nine months ended September 30, 2001:
Revenues $3,962 $193 $(642) $3,513
Net Income 419 1 -- 420
- -----------------------------------------------------------------------------------------
Nine months ended September 30, 2000:
Revenues $3,110 $229 $(377) $2,962
Net Income 429 2 -- 431
- -----------------------------------------------------------------------------------------
12 months ended September 30, 2001:
Revenues $4,972 $258 $(822) $4,408
Net Income 447 (1) -- 446
- -----------------------------------------------------------------------------------------
12 months ended September 30, 2000:
Revenues $3,829 $289 $(416) $3,702
Net Income 426 -- -- 426
- -----------------------------------------------------------------------------------------
* Elimination of intercompany revenues.
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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
Reference is made to Note 12 - Commitments and Contingencies to the "Notes
to Consolidated Financial Statements" on Pages 41 - 43 of the Registrant's 2000
Annual Report to Stockholders pages incorporated by reference in the
Registrant's Form 10-K for the year ended December 31, 2000, for a discussion of
the involvement of the Registrant's subsidiary, Union Electric Company
(AmerenUE), with a contaminated site in Sauget, Illinois. On September 13, 2001,
the United States Environmental Protection Agency (EPA) proposed that the Sauget
Area 1 and Sauget Area 2 sites be listed on the National Priorities List (NPL).
If successful, the listing of these sites on the NPL would permit the EPA to
access funds designated under the Comprehensive Environmental Response
Compensation Liability Act of 1980 (commonly known as CERCLA or Superfund) to
remediate the sites.
ITEM 5. OTHER INFORMATION.
The following material organizational changes have been made to senior
management by the Boards of Directors of the Registrant and certain of its
subsidiary companies:
Ameren Corporation
o Gary L. Rainwater was elected President and Chief Operating Officer,
effective August 30, 2001, reporting to Charles W. Mueller, who
remains Chairman and Chief Executive Officer. o Warner L. Baxter was
elected Senior Vice President, Finance, effective August 30, 2001,
replacing Donald E. Brandt, who resigned.
o Jerre E. Birdsong was elected Vice President and Treasurer, effective
October 12, 2001.
o Baxter A. Gillette was elected Vice President, Risk Management,
effective October 12, 2001.
o Martin J. Lyons, formerly a partner at PricewaterhouseCoopers, LLC,
was appointed Controller, effective October 22, 2001. Mr. Lyons
replaces Warner L. Baxter in this position.
Union Electric Company (Subsidiary)
o Gary L. Rainwater was elected President and Chief Operating Officer,
effective August 30, 2001, reporting to Charles W. Mueller, who became
Chairman, while retaining his title of Chief Executive Officer.
o Warner L. Baxter was elected Senior Vice President, Finance, effective
August 30, 2001, replacing Donald E. Brandt.
o Jerre E. Birdsong was elected Vice President and Treasurer, effective
October 12, 2001.
o Martin J. Lyons was appointed Controller, effective October 22, 2001,
replacing Warner L. Baxter.
Central Illinois Public Service Company (Subsidiary)
o Warner L. Baxter was elected Senior Vice President, Finance, effective
August 30, 2001.
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o Jerre E. Birdsong was elected Vice President and Treasurer, effective
October 12, 2001.
o Martin J. Lyons was appointed Controller, effective October 22, 2001,
replacing Warner L. Baxter.
AmerenEnergy Generating Company (Subsidiary)
o Daniel F. Cole was elected President, effective August 30, 2001,
replacing Gary L. Rainwater.
o Warner L. Baxter was elected Senior Vice President, Finance, effective
August 30, 2001.
o Jerre E. Birdsong was elected Vice President and Treasurer, effective
October 12, 2001.
o Martin J. Lyons was appointed Controller, effective October 22, 2001,
replacing Warner L. Baxter.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits. None.
(b) Reports on Form 8-K. The Registrant filed a report on Form 8-K
dated July 2, 2001 reporting that the Missouri Public Service
Commission (MoPSC) staff filed with the MoPSC an excess earnings
complaint against the Registrant's subsidiary, AmerenUE, that
proposes to reduce AmerenUE's annual electric revenues ranging
from $213 million to $250 million. Note: Reports of Union
Electric Company on Forms 8-K, 10-Q and 10-K are on file with the
SEC under File Number 1-2967.
Reports of Central Illinois Public Service Company on Forms
8-K,10-Q and 10-K are on file with the SEC under File Number
1-3672.
Information regarding AmerenEnergy Generating Company on Form S-4
is on file with the SEC under File Number 333-56594 and its
reports on Forms 8-K, 10-Q and 10-K are being filed with the SEC
under the same File Number.
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/ Warner L. Baxter
--------------------------------------
Warner L. Baxter
Senior Vice President, Finance
(Principal Financial Officer)
Date: November 14, 2001
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