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 The Quarterly Period Ended September 30, 2002
[ ] 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 333-56594
AMEREN ENERGY GENERATING COMPANY
(Exact name of registrant as specified in its charter)
Illinois 37-1395586
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1901 Chouteau Ave., 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 AmerenEnergy Generating Company's common stock as of
November 12, 2002: Common Stock, no par value, held by AmerenEnergy Development
Company (parent company of registrant) - 2,000
AMEREN ENERGY GENERATING COMPANY
INDEX
Page
PART I. Financial Information
ITEM 1. Financial Statements (Unaudited)
Balance Sheet at September 30, 2002 and December 31, 2001...................................... 2
Statement of Income for the three and nine months ended September 30, 2002 and 2001............ 3
Statement of Cash Flows for the nine months ended September 30, 2002 and 2001.................. 4
Statement of Common Stockholder's Equity for the three and nine months ended
September 30, 2002 and 2001.................................................................... 5
Notes to Financial Statements.................................................................. 6
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 14
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk..................................... 21
ITEM 4. Controls and Procedures........................................................................ 23
PART II. Other Information
ITEM 5. Other Information.............................................................................. 25
ITEM 6. Exhibits and Reports on Form 8-K............................................................... 25
SIGNATURE......................................................................................................... 25
CERTIFICATIONS.................................................................................................... 26
This Form 10-Q contains "forward-looking statements" within the meaning of
Section 21E of the Securities Exchange Act of 1934. Forward-looking statements
should be read with the cautionary statements and important factors included in
this Form 10-Q at Item 2. "Management's Discussion and Analysis of Financial
Condition and Results of Operations," under the heading "Safe Harbor Statement."
Forward-looking statements are all statements other than statements of
historical fact, including those statements that are identified by the use of
the words "anticipates," "estimates," "expects," "intends," "plans," "predicts,"
"projects," and similar expressions.
1
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
AMEREN ENERGY GENERATING COMPANY
BALANCE SHEET
(Unaudited, in millions, except shares)
September 30, December 31,
2002 2001
--------------- -------------
ASSETS:
Property and plant, at original cost:
Electric $ 2,295 $ 2,141
Less accumulated depreciation and amortization 731 689
--------------- -------------
1,564 1,452
Construction work in progress 27 60
--------------- -------------
Total property and plant, net 1,591 1,512
--------------- -------------
Current assets:
Cash and cash equivalents 3 2
Accounts receivable 9 8
Accounts receivable - intercompany 77 121
Notes receivable - intercompany 32 -
Materials and supplies, at average cost -
Fossil fuel 31 40
Other 26 20
Other 7 2
--------------- ---------------
Total current assets 185 193
--------------- ---------------
Deferred income taxes, net - 38
Other 27 13
--------------- ----------------
Total Assets $ 1,803 $ 1,756
=============== ================
CAPITAL AND LIABILITIES:
Capitalization:
Common stock, no par value, 10,000 shares authorized -
2,000 shares outstanding $ - $ -
Other paid-in capital 150 150
Retained earnings 139 120
Accumulated other comprehensive income 4 4
---------------- -----------------
Total common stockholder's equity 293 274
---------------- -----------------
Subordinated notes payable - intercompany 412 461
Long-term debt 698 424
---------------- -----------------
Total capitalization 1,403 1,159
---------------- -----------------
Current liabilities:
Current portion of subordinated notes payable - intercompany 50 47
Accounts and wages payable 30 63
Accounts and wages payable - intercompany 89 181
Notes payable - intercompany - 62
Current portion of income taxes payable - intercompany 13 18
Income taxes payable - 12
Interest payable 21 6
Interest payable - intercompany 8 6
Other 2 3
---------------- -----------------
Total current liabilities 213 398
---------------- -----------------
Deferred income taxes, net 1 -
Accumulated deferred investment tax credits 16 17
Income tax payable - intercompany 166 177
Other deferred credits and liabilities 4 5
---------------- -----------------
Total Capital and Liabilities $ 1,803 $ 1,756
================ =================
See Notes to Financial Statements.
2
AMEREN ENERGY GENERATING COMPANY
STATEMENT OF INCOME
(Unaudited, in millions)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ---------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------
OPERATING REVENUES:
Electric - intercompany $ 195 $ 223 $ 509 $ 509
Electric 35 100 163 225
Other - intercompany 2 3 8 10
------------- ------------- ------------- -------------
Total operating revenues 232 326 680 744
------------- ------------- ------------- -------------
OPERATING EXPENSES:
Operations
Fuel and purchased power 126 185 379 416
Other 29 24 87 74
------------- ------------- ------------- -------------
155 209 466 490
Maintenance 9 10 35 33
Depreciation and amortization 17 14 50 38
Other taxes 2 5 14 15
------------- ------------- ------------- -------------
Total operating expenses 183 238 565 576
------------- ------------- ------------- -------------
OPERATING INCOME 49 88 115 168
OTHER INCOME AND (DEDUCTIONS):
Miscellaneous, net -
Miscellaneous income (1) 2 (1) 5
Miscellaneous expense - 1 - -
------------- ------------- ------------- -------------
Total other income and (deductions) (1) 3 (1) 5
------------- ------------- ------------- -------------
INTEREST CHARGES:
Interest expense - intercompany 8 10 30 31
Interest expense 15 9 33 26
------------- ------------- ------------- -------------
Total interest charges 23 19 63 57
------------- ------------- ------------- -------------
INCOME TAXES 10 29 20 46
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE 15 43 31 70
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES - - - (2)
------------- ------------- ------------- -------------
NET INCOME $ 15 $ 43 $ 31 68
============= ============= ============= =============
See Notes to Financial Statements.
3
AMEREN ENERGY GENERATING COMPANY
STATEMENT OF CASH FLOWS
(Unaudited, in millions)
Nine Months Ended
September 30,
--------------------------
2002 2001
---------- ---------
Cash Flows From Operating:
Net income $ 31 $ 68
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting principle - 2
Depreciation and amortization 50 38
Deferred income taxes, net 20 11
Deferred investment tax credits, net (1) (1)
Other - (4)
Changes in assets and liabilities:
Accounts receivable (1) (1)
Accounts receivable - intercompany 44 (8)
Materials and supplies 3 (11)
Accounts and wages payable (33) 9
Accounts and wages payable - intercompany 48 81
Taxes payable (12) 21
Income taxes payable-intercompany (16) (12)
Interest payable 15 9
Interest payable - intercompany 2 -
Assets, other (16) (3)
Liabilities, other 17 2
---------- ---------
Net cash provided by operating activities 151 201
---------- ---------
Cash Flows Used In Investing:
Construction expenditures (268) (280)
Notes receivable - intercompany (32) 126
---------- ---------
Net cash used in investing activities (300) (154)
---------- ---------
Cash Flows From (Used In) Financing:
Dividends paid to Ameren (12) -
Debt issuance costs (4) -
Redemptions:
Subordinated notes payable - intercompany (46) (44)
Notes payable - intercompany (62) -
Issuances:
Long-term debt 274 -
---------- ---------
Net cash provided by (used in) financing activities 150 (44)
---------- ---------
Net change in cash and cash equivalents 1 3
Cash and cash equivalents at beginning of year 2 1
---------- ---------
Cash and cash equivalents at end of period $ 3 $ 4
========== =========
Cash paid during the periods:
Interest $ 27 $ 28
Interest - intercompany 17 17
Income taxes, net 4 22
See Notes to Financial Statements.
4
AMEREN ENERGY GENERATING COMPANY
STATEMENT OF COMMON STOCKHOLDER'S EQUITY
(Unaudited, in millions)
Three Months Ended Nine months Ended
September 30, September 30,
------------------------ --------------------------
2002 2001 2002 2001
----------- ----------- ------------ ------------
Common stock $ - $ - $ - $ -
Other paid-in capital
Beginning balance 150 - 150 -
Change in current period - - - -
----------- ----------- ------------ ------------
150 - 150 -
----------- ----------- ------------ ------------
Retained earnings
Beginning balance 133 69 120 44
Net income 15 43 31 68
Dividends paid to Ame (9) - (12) -
----------- ----------- ------------ ------------
139 112 139 112
----------- ----------- ------------ ------------
Accumulated other comprehensive income
Beginning balance 3 (2) 4 -
Change in current period (see below) 1 - - (2)
----------- ----------- ------------ ------------
4 (2) 4 (2)
----------- ----------- ------------ ------------
Total common stockholder's equity $ 293 $ 110 $ 293 $ 110
=========== =========== ============ ============
Comprehensive income, net of taxes
Net income $ 15 $ 43 $ 31 $ 68
Unrealized net gain/(loss) on derivative hedging instruments
(net of income taxes of $1, $-, $ - and $(1), respectively) 1 (1) - (1)
Reclassification adjustments for gains/(losses) included in net income
(net of income taxes of $ -, $ -, $- and $1, respectively) - 1 - 2
Cumulative effect of accounting change, net of income taxes of $(2) - - - (3)
----------- ----------- ------------ ------------
Total comprehensive income, net of taxes $ 16 $ 43 $ 31 $ 66
=========== =========== ============ ============
See Notes to Financial Statements.
5
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
September 30, 2002
NOTE 1 - Summary of Significant Accounting Policies
Basis of Presentation
Our financial statements reflect all adjustments (which include normal,
recurring adjustments) necessary, in our opinion, for a fair presentation of the
interim results. These statements should be read in conjunction with the
financial statements and the notes thereto included in our 2001 Annual Report on
Form 10-K.
When we refer to our, we or us, we are referring to AmerenEnergy Generating
Company and in some cases our agents, AmerenEnergy, Inc. (AmerenEnergy) and
AmerenEnergy Fuels and Services Company (Fuels Company). All tabular dollar
amounts are in millions, unless otherwise indicated.
Accounting Changes and Other Matters
In January 2001, we adopted Statement of Financial Accounting Standards
(SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities."
The impact of that adoption resulted in a cumulative effect charge of $2 million
after taxes to the income statement, and a cumulative effect adjustment of $3
million after taxes to Accumulated Other Comprehensive Income (OCI), which
reduced common stockholder's equity.
On January 1, 2002, we adopted SFAS No. 141, "Business Combinations," and
SFAS No. 142, "Goodwill and Other Intangible Assets." 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 allocate the purchase price to the assets and
liabilities of the acquired enterprise based on fair market value. SFAS 142
requires goodwill and indefinite-lived intangible assets 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 141 and SFAS 142 did not have any effect on our financial
position, results of operations or liquidity upon adoption. See Note 6 -
"CILCORP Acquisition."
In July 2001, SFAS No. 143, "Accounting for Asset Retirement Obligations,"
was issued. 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. Upon adoption we will be required to
recognize as a cumulative effect of a change in accounting principle,
depreciation expense that would have been recorded since the inception of the
long-lived assets to which the obligation relates. SFAS 143 is effective for us
on January 1, 2003. At this time, we are assessing the impact of SFAS 143 on our
financial position, results of operations and liquidity upon adoption, which
could be material.
On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." SFAS 144 addresses the financial accounting
and reporting for the impairment or disposal of long-lived assets and supersedes
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of." SFAS 144 retains the guidance related to
calculating and recording impairment losses, but adds guidance on the accounting
for discontinued operations, previously accounted for under Accounting
Principles Board Opinion No. 30. We evaluate long-lived assets for impairment
when events or changes in circumstances indicate that the carrying value of such
assets may not be recoverable. The determination of whether impairment has
occurred is based on an estimate of undiscounted cash flows attributable to the
assets, as compared with the carrying value of the assets. If impairment has
occurred, the amount of the impairment recognized is determined by estimating
the fair value of the assets and recording a provision for loss if the carrying
value is greater than the fair value. SFAS 144 did not have any effect on our
financial position, results of operations or liquidity upon adoption.
In June 2002, the Financial Accounting Standards Board (FASB) issued SFAS
No. 146, "Accounting for Costs Associated with Exit or Disposal Activities."
SFAS 146 requires an entity to recognize, and measure at fair value, a liability
for a cost associated with an exit or disposal activity in the period in which
the liability is incurred and nullifies Emerging Issues Task Force (EITF) Issue
No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and
Other Costs to Exit an Activity (Including Certain Costs Incurred in a
Restructuring)." SFAS 146 is effective for exit or disposal activities that are
initiated after December 31, 2002.
6
During the third quarter ended September 30, 2002, we adopted the
provisions of EITF Issue 02-3, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities," that require revenues and costs
associated with certain energy contracts to be shown on a net basis in the
income statement. Prior to the third quarter of 2002, our accounting practice
was to present all settled energy purchase or sale contracts within our power
risk management program on a gross basis in Operating Revenues and in Operating
Expenses - Operations - Fuel and Purchased Power. This meant that revenues were
recorded for the notional amount of the power sale contracts with a
corresponding charge to income for the costs of the energy that was generated,
or for the notional amount of a purchased power contract. We now report all
contracts within our power risk management program that have been purchased in
anticipation of future price changes on a net basis as a component of revenues
in the income statement. We have also applied this guidance to all prior periods
which had no impact on previously reported earnings or stockholder's equity. The
following table summarizes the impact of applying EITF Issue 02-3 on operating
revenues for the three and nine month periods ended September 30, 2002:
- ----------------------------------------------------------------------------------------------------------
Three months Nine months
- ----------------------------------------------------------------------------------------------------------
2002 2001 2002 2001
- ----------------------------------------------------------------------------------------------------------
Previously reported gross operating revenues $ 268 $ 329 $ 752 $ 747
Costs reclassified 36 3 72 3
- ----------------------------------------------------------------------------------------------------------
Net operating revenues reported in the income statement $ 232 $ 326 $ 680 $ 744
==========================================================================================================
In October 2002, the EITF reached a consensus to rescind EITF Issue No.
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." The effective date for the full rescission of Issue 98-10 will be
for fiscal periods beginning after December 15, 2002. In addition, the EITF
reached a consensus in October 2002 that all SFAS 133 trading derivatives
(subsequent to the rescission of Issue 98-10) should be shown net in the income
statement, whether or not physically settled. This consensus would apply to all
energy and non-energy related trading derivatives that meet the definition of a
derivative pursuant to SFAS 133. The FASB staff indicated that it would attempt
to address, through the October EITF meeting minutes process, the effective date
and transition provisions relating to this consensus. The rescission of EITF
98-10 and the related transition guidance could result in additional netting of
certain energy contracts beyond the netting required by EITF 02-3 discussed
above and have the effect of lowering our reported revenues and costs with no
impact on earnings. We are evaluating the impact of this consensus on our
financial statements.
Interchange Revenues
Interchange revenues included in Operating Revenues - Electric -
Intercompany and Electric were $53 million for the three months ended September
30, 2002 (2001 - $116 million) and $200 million for the nine months ended
September 30, 2002 (2001 - $254 million).
Purchased Power
Purchased power included in Operating Expenses - Operations - Fuel and
Purchased Power was $48 million for the three months ended September 30, 2002
(2001 - $119 million) and $194 million for the nine months ended September 30,
2002 (2001 - $269 million).
Employee Benefit Plans
Ameren Corporation, our parent company, made cash contributions totaling
$15 million to Ameren's defined benefit retirement plans during the third
quarter of 2002, and Ameren expects to make additional cash contributions to the
plans totaling approximately $15 million in the fourth quarter of 2002. Our
share of the cash contribution made in the third quarter of 2002 was
approximately $1 million, and we expect our share of the cash contribution that
may be made in the fourth quarter of 2002 will be approximately $1 million.
Future funding plans will be evaluated at the end of 2002. Based on the
performance of plan assets through September 30, 2002, Ameren expects to be
required under the Employee Retirement Income Security Act of 1974 to fund $25
million to $50 million in 2004 and $150 million to $200 million in 2005 in order
to maintain minimum funding levels. We expect our share of the funding to range
between $2 million and $5 million, and $14 million and $18 million for 2004 and
2005, respectively, plus our share related to employees of our affiliate, Ameren
Services Company. These amounts are estimates and may change based on actual
stock market performance, changes in interest rates, any plan funding in 2002 or
2003 and finalization of actuarial assumptions. In addition, we expect at
December 31, 2002 to be required to record a minimum pension liability that
would result in a charge to OCI in stockholder's equity. The amount of the
charge is expected to result in a less than one percent change in our debt to
total capitalization ratios.
7
NOTE 2 - Rate and Regulatory Matters
Missouri Electric
In order to satisfy its regulatory load requirements for 2001, our
affiliate, Union Electric Company, (operating as AmerenUE), purchased, under a
one year contract (the 2001 Marketing Company - AmerenUE agreement), 450
megawatts of capacity and energy from another of our affiliates, AmerenEnergy
Marketing Company (Marketing Company). Marketing Company acquired the power to
supply AmerenUE from us. This agreement was entered into through a competitive
bidding process and reflected market-based rates. For 2002, AmerenUE, similarly
entered into a one year contract with Marketing Company (the 2002 Marketing
Company - AmerenUE agreement) for the purchase of 200 megawatts of capacity and
energy at lower prices than in 2001. Through September 30, 2002, Marketing
Company has acquired the power to supply AmerenUE under the 2002 Marketing
Company - AmerenUE agreement from us, which because of the smaller quantity
purchased and the lower prices, has resulted in lower revenues to us.
In May 2001, the Missouri Public Service Commission (MoPSC) filed a
complaint with the Securities and Exchange Commission (SEC) relating to the 2001
Marketing Company - AmerenUE agreement. The complaint requested an investigation
into the contractual relationship between AmerenUE, Marketing Company and us, in
the context of the 2001 Marketing Company - AmerenUE agreement and requested
that the SEC find that such relationship violates Section 32(k) of the Public
Utility Holding Company Act of 1935 (PUHCA), which requires state utility
commission approval of power sales contracts between an electric utility company
and an affiliated electric wholesale generator, like us. We have asserted that
the MoPSC's approval of the power sales agreement under PUHCA is not required
because we are not a party to the agreement. In its SEC complaint, the MoPSC
proposes that the SEC require AmerenUE to contract directly with us and submit
such contract to the MoPSC for review. On May 9, 2002, the MoPSC filed a similar
complaint with the SEC relating to the 2002 Marketing Company - AmerenUE
agreement. While the SEC is still investigating these matters, the MoPSC and
AmerenUE have tentatively reached agreement for resolving these disputes. The
agreement reached requires AmerenUE to not enter into any new contracts to
purchase wholesale electric energy from any Ameren affiliate that is an exempt
wholesale generator without first obtaining, on a timely basis, the
determinations required of the MoPSC that are specified in Section 32(k) of
PUHCA. However, this commitment does not prevent AmerenUE from completing the
purchases contemplated by the 2001 and 2002 Marketing Company - AmerenUE
agreement and making short term energy purchases (less than 90 days) from an
Ameren affiliate, without prior MoPSC determination, to prevent or alleviate
system emergencies. As part of the tentative agreement, the MoPSC has agreed to
terminate its SEC complaints.
Also, with respect to the 2002 Marketing Company - AmerenUE agreement, on
May 31, 2002, the Federal Energy Regulatory Commission (FERC) accepted the
agreement, subject to refund, and scheduled the matter for a January 2003
hearing to assess the appropriateness of the rates charged. In October 2002,
Marketing Company and the FERC Staff jointly reported to the FERC that they have
negotiated a settlement in principle of the issues that had been set for
hearing, and that they both expect that the settlement will be uncontested.
Other than a slight modification to the procedures for establishing off-peak
energy prices under the agreement, the settlement in principle will have no
impact on the agreement's price, terms and conditions. The settlement in
principle also establishes guidelines for AmerenUE to follow when conducting
future requests for proposals for the purpose of pursuing long-term power
purchases.
Until the SEC and the FERC issue final orders in these proceedings,
management is unable to predict their ultimate impact on our future financial
position, results of operations or liquidity.
Illinois Electric
In December 1997, the Electric Service Customer Choice and Rate Relief Law
of 1997 (the Illinois Law) was enacted providing for electric utility
restructuring in Illinois. This legislation introduced competition into the
retail supply of electric energy in Illinois. Illinois residential customers
were offered choice in suppliers beginning on May 1, 2002. Industrial and
commercial customers were previously offered this choice.
The original Illinois Law contained a provision freezing retail bundled
electric rates through January 1, 2005. In 2002, legislation was passed and
signed into law that extended the rate freeze period through January 1, 2007. As
a result of the extension through January 1, 2007 of the electric rate freeze
related to the Illinois Law, Marketing Co. expects to seek to renew or extend a
power supply agreement between our affiliate, Central Illinois Public Service
Company (operating as AmerenCIPS) and Marketing Company through the same period.
A renewal or extension of
8
the power supply agreement will depend on compliance with regulatory
requirements in effect at the time, and we cannot predict whether we will be
successful in securing a renewal or extension of this agreement. The offering of
choice to the industrial and commercial customers of AmerenCIPS, which is
indirectly supplied power by us through Marketing Co., has not had a material
adverse effect on our business and we do not expect the offering of choice to
AmerenCIPS' residential customers, or the extension of the rate freeze, to have
a material adverse effect on our business.
Federal - Electric Transmission
In December 1999, the FERC issued Order 2000 requiring all utilities,
subject to FERC jurisdiction, to state their intentions for joining a regional
transmission organization (RTO). RTOs are independent organizations that will
functionally control the transmission assets of utilities in order to improve
the wholesale power market. Since January 2001, our affiliates, AmerenUE and
AmerenCIPS, along with several other utilities, were seeking approval from the
FERC to participate in an RTO known as the Alliance RTO. The Ameren companies
had previously been members of the Midwest Independent System Operator (Midwest
ISO) and recorded a pretax charge to earnings in 2000 of $25 million ($15
million after taxes) for an exit fee and other costs when they left that
organization. Ameren felt the for-profit Alliance RTO business model was
superior to the not-for-profit Midwest ISO business model and provided it with a
more equitable return on its transmission assets.
In late 2001, the FERC issued an order that rejected the formation of the
Alliance RTO and ordered the Alliance RTO companies and the Midwest ISO to
discuss how the Alliance RTO business model could be accommodated within the
Midwest ISO. On April 25, 2002, after the Alliance RTO and Midwest ISO failed to
reach an agreement, and after a series of filings by the two parties with the
FERC, the FERC issued a declaratory order setting forth the division of
responsibilities between the Midwest ISO and National Grid (the managing member
of the transmission company formed by the Alliance companies) and approved the
rate design and the revenue distribution methodology proposed by the Alliance
companies. However, the FERC denied a request by the Alliance companies and
National Grid to purchase certain services from the Midwest ISO at incremental
cost rather than the Midwest ISO's full tariff rates. The FERC also ordered the
Midwest ISO to return the exit fee paid by the Ameren companies to leave the
Midwest ISO, provided the Ameren companies return to the Midwest ISO and agree
to pay their proportional share of the startup and ongoing operational expenses
of the Midwest ISO. Moreover, the FERC required the Alliance companies to select
the RTO in which they will participate within thirty days of the order.
Since the April 2002 FERC order, AmerenUE and AmerenCIPS made filings with
the FERC indicating that they would return to the Midwest ISO and that
membership would be through a new independent transmission company, GridAmerica
LLC, that was agreed to be formed by AmerenUE and AmerenCIPS, and subsidiaries
of FirstEnergy Corporation and NiSource Inc. If the FERC approves the definitive
agreements establishing GridAmerica, a subsidiary of National Grid will serve as
the managing member of GridAmerica and will manage the transmission assets of
the three companies and participate in the Midwest ISO on behalf of GridAmerica.
Other Alliance RTO companies announced their intentions to join the PJM
Interconnection LLC (PJM) RTO. On July 25, 2002, the Ameren companies filed a
motion with the FERC requesting that it condition the approval of the choices of
other Illinois utilities to join the PJM RTO on Midwest ISO and PJM entering
into an agreement addressing important reliability and rate-barrier issues. On
July 31, 2002, the FERC issued an order accepting the formation of GridAmerica
as an independent transmission company under the Midwest ISO subject to further
compliance filings ordered by the FERC. The FERC also issued an order accepting
the elections made by the other Illinois utilities to join the PJM RTO on the
condition PJM and Midwest ISO immediately begin a process to address the
reliability and rate-barrier issues raised by the Ameren companies and other
market participants in previous filings.
We do not own transmission assets. However, we pay AmerenUE and AmerenCIPS
for the use of their transmission lines to transmit power. Until the reliability
and rate-barrier issues are resolved as ordered by the FERC, and the tariffs and
other material terms of Ameren's participation in GridAmerica, and GridAmerica's
participation in the Midwest ISO, are finalized and approved by the FERC, Ameren
is unable to predict whether the Ameren companies will in fact become a member
of GridAmerica or Midwest ISO, or the impact that on-going RTO developments will
have on the financial condition, results of operation or liquidity of Ameren or
its subsidiaries, including us.
On July 31, 2002, the FERC issued its standard market design notice of
proposed rulemaking (NOPR). The NOPR proposes a number of changes to the way the
current wholesale transmission service and energy markets are operated.
Specifically, the NOPR calls for all jurisdictional transmission facilities to
be placed under the control of an independent transmission provider (similar to
an RTO), proposes a new transmission service tariff that provides a single form
of transmission service for all users of the transmission system including
bundled retail load, and
9
proposes a new energy market and congestion management system that uses
locational marginal pricing as its basis. Ameren is currently evaluating the
NOPR and its possible impact on operations and expects to file comments on the
NOPR with the FERC in November 2002. Until the FERC issues a final rule,
management is unable to predict the ultimate impact on our future financial
position, results of operations or liquidity.
NOTE 3 - Related Party Transactions
We have transactions in the normal course of business with Ameren
Corporation, our parent company, and Ameren's other subsidiaries. These
transactions primarily consist of power purchases and sales, services received
or rendered, borrowings and lendings. The transactions with these affiliates are
reported as intercompany transactions.
Electric Power Supply Agreements
An electric power supply agreement was entered into between us and
Marketing Co. (Genco-Marketing Co. agreement). Marketing Co. entered into an
electric power supply agreement with AmerenCIPS (Marketing Co.-CIPS agreement)
to supply sufficient power to meet AmerenCIPS' native load requirements. A
portion of the capacity and energy supplied by us to Marketing Co. is resold to
AmerenCIPS for resale. The portion of these sales to AmerenCIPS that is used for
resale to native load customers is at rates (which approximate the historical
regulated rates for generation) specified by the Illinois Commerce Commission
(ICC). Another portion of the sales to AmerenCIPS is resold to those retail
customers that elected fixed market-based prices. Other capacity and energy
purchased by Marketing Co. from us will be used by Marketing Co. to serve its
obligations under various long-term wholesale contracts it assumed from
AmerenCIPS and obligations it has, or will have under other long-term wholesale
and retail contracts. The Marketing Co.-CIPS agreement expires December 31, 2004
and the Genco-Marketing Co. agreement may be terminated upon at least one year's
notice given by either party, but in no event can it be terminated prior to
December 31, 2004. As a result of the extension through January 1, 2007 of the
electric rate freeze related to the Illinois Law, we expect Marketing Co. to
seek to renew or extend the Marketing Co.-CIPS agreement through the same
period. A renewal or extension of the Marketing Co.-CIPS agreement will depend
on compliance with regulatory requirements in effect at the time, and we cannot
predict whether Marketing Co. will be successful in securing a renewal or
extension of this agreement. Electric revenues derived under the Genco-Marketing
Co. agreement were $177 million for the three months ended September 30, 2002
(2001 - $207 million) and $472 million for the nine months ended September 30,
2002 (2001 - $479 million). No other customer represents greater than 10% of our
revenues.
Joint Dispatch Agreement
We jointly dispatch generation with AmerenUE under an amended joint
dispatch agreement. Under the amended agreement, both of us are entitled to
serve our load requirements from our own least-cost generation first, and then
allow the other company access to any available excess generation. All of our
sales to Marketing Co. are considered load requirements. Sales made by us to
other customers through AmerenEnergy, as our agent, are not considered load
requirements. The agreement has no expiration, but either party may give a one
year notice of termination beginning January 1, 2004. Termination of this
agreement could have a material adverse impact on our business.
Electric revenues derived through sales of available generation through
AmerenEnergy were $35 million for the three months ended September 30, 2002
(2001 - $100 million) and $163 million for the nine months ended September 30,
2002 (2001 - $225 million). These amounts are inclusive of the adjustments made
associated with EITF Issue 02-3. See Note 1 - "Summary of Significant Accounting
Policies." Electric revenues derived through sales of available generation to
AmerenUE through the amended joint dispatch agreement were $15 million for the
three months ended September 30, 2002 (2001 - $15 million) and $33 million for
the nine months ended September 30, 2002 (2001 - $29 million).
Intercompany power purchases from the amended joint dispatch agreement
between AmerenUE and us and other agreements for the three months ended
September 30, 2002 were $16 million (2001 - $18 million) and $51 million for the
nine months ended September 30, 2002 (2001 - $59 million).
10
Other Electric Revenues - Intercompany
Electric revenues derived through sales of available generation to our
affiliate Electric Energy, Inc. were $3 million for the three months ended
September 30, 2002 (2001 - less than $1 million) and $4 million for the nine
months ended September 30, 2002 (2001 - less than $1 million).
Ameren Services and AmerenEnergy Charges
Support services provided by our affiliates, Ameren Services and
AmerenEnergy, including wages, employee benefits, professional services and
other expenses are based on actual costs incurred. Other Operating Expenses
provided by Ameren Services and AmerenEnergy, for the three months ended
September 30, 2002, were $10 million (2001 - $7 million) and $27 million for the
nine months ended September 30, 2002 (2001 - $24 million).
Other
Our gross margins from power supply contracts with affiliated companies
continue to be the principal source of cash from operating activities. We plan
to utilize short-term debt to support normal operations and other temporary
capital requirements. We have the ability to borrow up to $800 million from
Ameren Corporation through a non-utility money pool agreement. However, the
total amount available to us at any time is reduced by the amount of borrowings
from Ameren by our affiliates and is increased to the extent other Ameren
non-regulated companies advance surplus funds to the non-utility money pool or
external borrowing sources are used by Ameren to increase the available amounts.
At September 30, 2002, $800 million was available through the non-utility money
pool not including additional funds available through invested cash balances at
Ameren Corporation and uncommitted bank lines. The non-utility money pool was
established to coordinate and provide for short-term cash and working capital
requirements of Ameren's non-regulated activities and is administered by Ameren
Services. Interest is calculated at varying rates of interest depending on the
composition of internal and external funds in the non-utility money pool. The
average interest rate for borrowings from the non-utility money pool was 8.84%
in the third quarter of 2002 (2001 - 3.66%) and 7.18% for the nine months ended
September 30, 2002 (2001 - 4.68%). These rates are based on the cost of Ameren's
funds used to fund money pool advances. We earned less than $1 million in net
intercompany interest income associated with outstanding loans to the
non-utility money pool in the third quarter of 2002 and incurred $5 million in
net intercompany interest expense associated with outstanding borrowings from
the non-utility money pool for the nine months ended September 30, 2002. We
incurred less than $1 million in net intercompany interest expense associated
with outstanding borrowings from the non-utility money pool in the third quarter
of 2001 compared to earning $2 million of net intercompany interest income
associated with outstanding loans to the non-utility money pool for the nine
months ended September 30, 2001. At September 30, 2002, we had loaned $32
million to the non-utility money pool and had no outstanding borrowings.
NOTE 4 - Derivative Financial Instruments
Derivative Financial Instruments
We, through AmerenEnergy and Fuels Company acting as agents on our behalf,
utilize derivatives principally to manage the risk of changes in market prices
for fuel, electricity and emission credits. Price fluctuations in fuel and
electricity cause:
o an unrealized appreciation or depreciation in the value of our firm
commitments to purchase or sell when purchase or sales prices under the
firm commitment are compared with current commodity prices;
o market values of fuel or purchased power to differ from the cost of those
commodities in inventory or under the firm commitment; and
o actual cash outlays for the purchase of these commodities, in certain
circumstances, to differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are dictated by risk
management policies and include forward contracts, futures contracts, options
and swaps. We continually assess our supply and delivery commitment positions
against forward market prices and internal forecasts of forward prices. We
actively manage our exposure to power price risk through our power risk
management program carried out under our risk management guidelines to modify
our exposure to market, credit and operational risk by entering into various
offsetting transactions. In general, we believe these transactions serve to
reduce our price risk.
11
In addition, we may purchase additional power again within risk management
guidelines, in anticipation of future price changes. Certain derivative
contracts we enter into on a regular basis as part of our power risk management
program do not qualify for hedge accounting or the normal purchase, normal sale
exception under SFAS 133. Accordingly, these contracts are recorded at fair
value with changes in the fair value charged or credited to the income statement
in the period in which the change occurred. Contracts we enter into as part of
our power risk management program may be settled by either physical delivery or
financially settled with the counterparty. See Note 1 - "Summary of Significant
Accounting Policies."
As of September 30, 2002, we have recorded the fair value of derivative
financial instrument assets of $2 million in Other Assets and the fair value of
derivative financial instrument liabilities of $2 million in Other Deferred
Credits and Liabilities.
Cash Flow Hedges
We routinely enter into forward purchase and sales contracts for
electricity based on forecasted levels of economic generation in excess of load
requirements. The relative balance between load and economic generation varies
throughout the year. 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. We
formally document all relationships between hedging instruments and hedged
items, as well as our risk management objective and strategy for undertaking
various hedge transactions. The mark-to-market value of cash flow hedges will
continue to fluctuate with changes in market prices up to contract expiration.
The pretax net gain or loss on power forward derivative instruments, 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
OCI due to transactions going to delivery or settlement, was approximately a $1
million loss for the three months ended September 30, 2002, and approximately a
$1 million loss for the nine months ended September 30, 2002. For the three and
nine months ended September 30, 2001, the above related amounts were
approximately a $1 million gain and a $4 million gain, respectively.
As of September 30, 2002, we had hedged a portion of the electricity price
exposure for the upcoming twelve-month period. The mark-to-market value
accumulated in OCI for the effective portion of hedges of electricity price
exposure was a gain of less than $1 million.
As of September 30, 2002, a gain of approximately $6 million ($4 million,
net of taxes) associated with interest rate swaps was included in OCI. The swaps
were a partial hedge of the interest rate on long-term debt that was issued in
June 2002. The swaps covered the first ten years of debt that has a 30-year
maturity and the gain in OCI is being amortized over a ten-year period beginning
in June 2002.
NOTE 5 - Debt
In June 2002, we issued $275 million of 7.95% Senior Notes due June 1, 2032
in a Rule 144A private placement. Interest is payable semi-annually on June 1
and December 1 of each year, beginning December 1, 2002. We received net
proceeds of $271 million, after debt discount and underwriters' fees, that were
used to reduce short-term borrowings and for general corporate purposes. The
indenture underlying these and other outstanding senior notes limits our ability
to, among other things, sell assets, create liens, and engage in mergers,
consolidations or similar transactions. In addition, the indenture includes
transitional covenants that limit our ability to incur indebtedness and pay
dividends or make certain other restricted payments. We are currently in
compliance with all covenants relating to this debt as well as to other
outstanding debt. In October 2002, we filed a registration statement with the
SEC on Form S-4 to permit an exchange offer of the 7.95% Senior Notes.
Amortization of debt issuance costs and discounts for the three and nine
months ended September 30, 2002 and 2001 of less than $1 million and
approximately $1 million, respectively, were included in interest expense.
NOTE 6 - CILCORP Acquisition
On April 28, 2002, Ameren entered into an agreement with The AES
Corporation (AES) to purchase all of the outstanding common stock of CILCORP
Inc. CILCORP is the parent company of Peoria, Illinois-based Central Illinois
Light Company, which operates as CILCO. Ameren also agreed to acquire AES Medina
Valley (No. 4), L.L.C. which indirectly owns a 40 megawatt, gas-fired electric
generation plant. The total purchase price is approximately $1.4 billion,
subject to adjustment for changes in CILCORP's working capital, and includes the
assumption of CILCORP and AES
12
Medina Valley debt at closing, estimated at approximately $900 million, with the
balance of the purchase price payable in cash. Ameren expects to finance a
significant portion of the cash component of the purchase price through prior
and future issuances of new common equity.
The purchase will include CILCORP's regulated natural gas and electric
businesses in Illinois serving approximately 205,000 and 200,000 customers,
respectively, of which approximately 150,000 are combination electric and gas
customers. CILCO's service territory is contiguous to AmerenCIPS' service
territory. In addition, the purchase includes approximately 1,200 megawatts of
largely coal-fired generating capacity, most of which is expected to be
non-regulated in 2003. Ameren currently does not plan to transfer any portion of
this non-regulated generating capacity to us.
Upon completion of the acquisition, expected by March 2003, CILCO will
become an Ameren subsidiary, but will remain a separate utility company,
operating as AmerenCILCO. The transaction is subject to the approval of the ICC,
the FERC, the SEC under PUHCA and the Federal Communications Commission, as well
as the expiration of the waiting period under the Hart-Scott-Rodino Antitrust
Improvements Act and other customary closing conditions. Applications to all
applicable regulatory agencies were made and are proceeding through the approval
process. On August 30, 2002, Ameren and AES received from the U.S. Department of
Justice (DOJ), a Request for Additional Information (Second Request) under the
Hart-Scott-Rodino Act pertaining to the CILCORP acquisition. Ameren intends to
respond to the Second Request by the end of November. Under the stock purchase
agreement with AES, Ameren is obligated to resolve any issues raised by the DOJ
in connection with the Hart-Scott-Rodino filing. Although issuance of a Second
Request is not unusual for transactions of this size, it does extend the review
and waiting period under the Act. Ameren does not expect that this extension
will impact the anticipated transaction closing date. In October 2002, Ameren
resolved all outstanding issues related to the CILCORP acquisition with the ICC
Staff and all interveners that filed testimony in the case. The principal issue,
among other things, related to the potential exercise of market power within the
CILCO service territory. To address this issue Ameren has agreed to invest
approximately $23 million by December 31, 2008 to increase the power import
capability into CILCO's service territory. The parties expect to agree upon a
draft proposed Order for presentation to the ICC in November, which is expected
to issue a final Order by the end of the year.
For the nine-month period ended September 30, 2002, CILCORP had revenues of
$579 million, operating income of $79 million, and net income from continuing
operations of $29 million, and as of September 30, 2002 had total assets of $1.9
billion. For the year ended December 31, 2001, CILCORP had revenues of $815
million, operating income of $126 million, and net income from continuing
operations of $28 million, and as of December 31, 2001 had total assets of $1.8
billion.
NOTE 7 - Subsequent Event
On November 4, 2002 Ameren Corporation announced a voluntary retirement
program that is being offered to approximately 1,000 of its 7,400 employees,
including employees providing support functions to us through Ameren Services
and approximately 85 of our employees. In addition, Ameren announced limits on
its contributions and increased retiree contributions for certain retiree
medical benefit plans and a freeze on wage increases beginning in 2003 for all
management employees, including our management employees. While we and Ameren
expect to realize significant long-term savings as a result of this program, we
expect to incur a one-time, after-tax charge in the fourth quarter of 2002
related to the program. That charge for Ameren could range between $30 million
and $50 million, based on voluntary retirements ranging between 300 and 500,
respectively. We expect to be allocated a portion of the charges depending on
the amount of retirements within our company and Ameren Services. In addition to
the voluntary retirement program, we and Ameren may consider implementing an
involuntary severance program if it is determined that additional positions must
be eliminated to achieve optimum organizational efficiency and effectiveness.
Further, we and Ameren will continue to seek other ways to reduce staffing over
the next year to reduce costs and gain efficiencies in operations.
13
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
OVERVIEW
AmerenEnergy Generating Company, is an indirect wholly-owned subsidiary of
Ameren Corporation (Ameren) that owns and operates a wholesale electric
generation business in Missouri and Illinois. Much of our business was formerly
owned and operated by our affiliate, Central Illinois Public Service Company,
which operates as AmerenCIPS. We were incorporated in the State of Illinois in
March 2000. On May 1, 2000, we acquired from AmerenCIPS at net book value five
coal-fired electric generating stations which we refer to as the coal plants,
all related fuel, supply, transportation, maintenance and labor agreements,
approximately 45% of AmerenCIPS' employees, and other related rights, assets and
liabilities.
Ameren is a holding company registered under the Public Utility Holding
Company Act of 1935 (PUHCA). Its principal business is the generation,
transmission and distribution of electricity, and the distribution of natural
gas to residential, commercial, industrial and wholesale users in the central
United States. In addition to us, Ameren's principal subsidiaries and our
affiliates are as follows:
o Union Electric Company, which operates a regulated electric generation,
transmission and distribution business, and a regulated natural gas
distribution business in Missouri and Illinois as AmerenUE.
o AmerenCIPS, which operates a regulated electric and natural gas
distribution business in Illinois.
o AmerenEnergy Resources Company (Resources Company), which consists of non
rate-regulated operations. Its principal subsidiaries include us,
AmerenEnergy Marketing Company (Marketing Company) which markets power for
periods over one year, AmerenEnergy Fuels and Services Company (Fuels
Company), which procures fuel and natural gas and manages the related risks
for us and our affiliates, and AmerenEnergy Development Company
(Development Company), which, as our parent, develops and constructs
generating facilities for us.
o AmerenEnergy, Inc. (AmerenEnergy), which serves as a power marketing and
risk management agent for us and our affiliates for transactions of less
than one year.
o Electric Energy, Inc. (EEI) which owns and/or operates electric generation
and transmission facilities in Illinois. Ameren has a 60% ownership
interest in EEI, 40% owned by AmerenUE and 20% owned by Resources Company.
o Ameren Services Company (Ameren Services), which provides shared support
services to us and our affiliates.
You should read the following discussion and analysis in conjunction with:
o The financial statements and related notes included in this Quarterly
Report on Form 10-Q.
o The audited financial statements and related notes that are included in our
Annual Report on Form 10-K for the year ended December 31, 2001.
o Management's Discussion and Analysis of Financial Condition and Results of
Operations that is included in our Annual Report on Form 10-K for the year
ended December 31, 2001.
When we refer to our, we or us, we are referring to AmerenEnergy Generating
Company and in some cases our agents, AmerenEnergy and Fuels Company. All
tabular dollar amounts are in millions, unless otherwise indicated.
Our results of operations and financial position are impacted by many
factors, including both controllable and uncontrollable factors. Weather,
economic conditions, and the actions of key customers or competitors can
significantly impact the demand for our services. Our results are also impacted
by seasonal fluctuations caused by winter heating, and summer cooling, demand.
We principally utilize coal and natural gas in our operations. The prices for
these commodities can fluctuate significantly due to the world economic and
political environment, weather, production levels and many other factors. We
employ various risk management strategies in order to try to reduce our exposure
to commodity risks and other risks inherent in our business. The reliability of
our power plants, and the level of operating and administrative costs and
capital investment are key factors that we seek to control in order to optimize
our results of operations, cash flows and financial position.
14
RESULTS OF OPERATIONS
Summary
Our net income decreased to $15 million in the third quarter of 2002 from
$43 million in the third quarter of 2001. Net income for the nine months ended
September 30, 2002 decreased to $31 million from $68 million in the same
year-ago period. The decrease in both periods was primarily due to a decrease in
electric margin (third quarter - $20 million, net of taxes; year to date - $15
million, net of taxes) resulting, in part, from the expiration of the 2001 450
megawatt power supply agreement between Marketing Company and AmerenUE which was
supplied by us (2001 Marketing Co. - AmerenUE agreement) offset by a new 2002
megawatt supply agreement with AmerenUE and increases in sales to new and
existing wholesale customers. In addition, the decrease in earnings was also
partially attributable to increases in other operation costs primarily
associated with increases in workers' compensation and pension and healthcare
costs coupled with increased costs for efficiency improvements made at our power
plants, increases in depreciation associated with additional combustion turbine
generating units added since the third quarter of 2001 (third quarter - $2
million, net of taxes; year to date - $7 million, net of taxes), and higher
interest costs associated with borrowing more funds at higher interest rates
(third quarter - $2 million, net of taxes; year to date - $4 million, net of
taxes). In the first quarter of 2001, we recorded a charge of $2 million due to
the adoption of Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities."
Recent Developments
2003 Outlook and Voluntary Retirement Plan
See "Liquidity and Capital Resources - Outlook" for a discussion of
expected challenges to net income in 2003 and beyond, along with a voluntary
retirement plan that was offered to approximately 1000 Ameren employees in early
November 2002 and is expected to result in a fourth quarter 2002 after-tax
charge to Ameren of between $30 million and $50 million.
CILCORP Acquisition
On April 28, 2002, Ameren entered into an agreement with The AES
Corporation (AES) to purchase all of the outstanding common stock of CILCORP
Inc. CILCORP is the parent company of Peoria, Illinois-based Central Illinois
Light Company, which operates as CILCO. Ameren also agreed to acquire AES Medina
Valley (No. 4), L.L.C. which indirectly owns a 40 megawatt, gas-fired electric
generation plant. The total purchase price is approximately $1.4 billion,
subject to adjustment for changes in CILCORP's working capital, and includes the
assumption of CILCORP and AES Medina Valley debt at closing, estimated at
approximately $900 million, with the balance of the purchase price payable in
cash. Ameren expects to finance a significant portion of the cash component of
the purchase price through prior and future issuances of new common equity.
The purchase will include CILCORP's regulated natural gas and electric
businesses in Illinois serving approximately 205,000 and 200,000 customers,
respectively, of which approximately 150,000 are combination electric and gas
customers. CILCO's service territory is contiguous to AmerenCIPS' service
territory. In addition, the purchase includes approximately 1,200 megawatts of
largely coal-fired generating capacity, most of which is expected to be
non-regulated in 2003. Ameren currently does not plan to transfer any portion of
this non-regulated generating capacity to us.
Upon completion of the acquisition, expected by March 2003, CILCO will
become an Ameren subsidiary, but will remain a separate utility company,
operating as AmerenCILCO. The transaction is subject to the approval of the
Illinois Commerce Commission, the Securities and Exchange Commission (SEC) under
PUHCA, the Federal Energy Regulatory Commission (FERC), and the Federal
Communications Commission, as well as the expiration of the waiting period under
the Hart-Scott-Rodino Antitrust Improvements Act and other customary closing
conditions. Applications to all applicable regulatory agencies were made and are
proceeding through the approval process. On August 30, 2002, Ameren and AES
received from the U.S. Department of Justice (DOJ), a Request for Additional
Information (Second Request) under the Hart-Scott-Rodino Act pertaining to the
CILCORP acquisition. Ameren intends to respond to the Second Request by the end
of November. Under the stock purchase agreement with AES, Ameren is obligated to
resolve any issues raised by the DOJ in connection with the Hart-Scott-Rodino
filing. Although issuance of a Second Request is not unusual for transactions of
this size, it does extend the review and waiting period under the Act. Ameren
does not expect that this extension will impact the anticipated transaction
closing date. In October 2002, Ameren resolved all outstanding issues related to
the CILCORP acquisition with the
15
ICC Staff and all interveners that filed testimony in the case. The principal
issue, among other things, related to the potential exercise of market power
within the CILCO service territory. To address this issue Ameren agreed to
invest approximately $23 million by December 31, 2008 to increase the power
import capability into CILCO's service territory. The parties expect to agree
upon a draft proposed Order for presentation to the ICC in November, which is
expected to issue a final Order by the end of the year.
For the nine-month period ended September 30, 2002, CILCORP had revenues of
$579 million, operating income of $79 million, and net income from continuing
operations of $29 million, and as of September 30, 2002 had total assets of $1.9
billion. For the year ended December 31, 2001, CILCORP had revenues of $815
million, operating income of $126 million, and net income from continuing
operations of $28 million, and as of December 31, 2001 had total assets of $1.8
billion.
In April 2002, as a result of AmerenUE's then pending Missouri electric
earnings complaint case and the CILCORP transaction and related assumption of
debt, credit rating agencies placed Ameren Corporation's debt under review for
possible downgrade or negative credit watch. Standard & Poor's placed the
ratings of AmerenUE and AmerenCIPS debt on negative credit watch and placed the
ratings of our debt on positive credit watch. Standard & Poor's stated it
expects the corporate credit ratings of Ameren and its subsidiaries to be in the
"A" rating category following completion of the acquisition. Moody's Investor
Service stated it envisioned a one notch downgrade of Ameren's issuer, senior
unsecured debt and commercial paper ratings. Ameren's corporate credit rating is
"A+" at Standard & Poor's and its issuer rating is "A2" at Moody's, while our
credit rating is "BBB+" at Standard and Poor's and "A3" (for our senior notes
due 2005) and Baa2 (for our other outstanding series of senior notes due 2010
and 2032) at Moody's. In July 2002, AmerenUE settled its electric earnings
complaint case. Neither Standard & Poor's nor Moody's has changed the assignment
of negative or positive watch, review for possible downgrade or negative outlook
to any of their ratings nor have the ratings themselves changed. Subsequent to
the settlement of the Missouri electric earnings complaint case, Fitch Ratings
reduced AmerenUE's ratings by one notch (from "AA" to "AA-" in the case of its
first mortgage bonds) and changed the outlook assigned to AmerenUE's ratings
from negative to stable. Any adverse change in the Ameren companies' ratings may
reduce their access to capital and/or increase the costs of borrowings resulting
in a negative impact on earnings. A credit rating is not a recommendation to
buy, sell or hold securities and should be evaluated independently of any other
rating. Ratings are subject to revision or withdrawal at any time by the
assigning rating organization.
Electric Operations
The following table represents the favorable (unfavorable) variations for
the three and nine months ended September 30, 2002 from the comparable periods
in 2001:
- --------------------------------------------------------------------------------
Three Months Nine Months
- --------------------------------------------------------------------------------
Electric Revenues:
Wholesale revenues......................... $ (30) $ (7)
Interchange revenues....................... (63) (55)
- --------------------------------------------------------------------------------
(93) (62)
Fuel and Purchased Power:
Fuel:
Generation............................... $ (14) $ (37)
Price.................................... (1) (5)
Generation efficiencies and other........ 3 4
Purchased power............................ 71 75
- --------------------------------------------------------------------------------
59 37
- --------------------------------------------------------------------------------
Change in electric margin $ (34) $ (25)
================================================================================
Electric margins decreased $34 million for the three months ended September
30, 2002 and $25 million for the nine months ended September 30, 2002 compared
to the same year-ago periods primarily due to the absence of revenues from the
2001 Marketing Co - AmerenUE agreement during the third quarter of 2002 and a
slight decrease in volume of interchange sales for the year which provided lower
margins due to lower electricity prices, partially offset by a net increase in
new wholesale customers added by Marketing Company, an increase in sales to
existing wholesale customers due to warmer weather and an increase in the use of
lower cost generation stations due to better availability. Electric revenues
decreased $93 million in the third quarter of 2002 and $62 million in the first
nine months of 2002. These changes were primarily due to the absence of the
higher margin 2001 Marketing Co. - AmerenUE agreement and a 26% decline in
interchange kilowatthour sales for the quarter (4% year to date).
16
However, these declines were offset by warmer weather and several new wholesale
electric customers added by Marketing Co. which together contributed an
additional $19 million of electric revenues for the quarter and $43 million year
to date. The reduction in purchased power in the third quarter and year to date
compared to year-ago periods corresponds to the decline in interchange sales and
was also reduced due to fewer forced and maintenance outages at our coal plants
and lower prices.
During the third quarter ended September 30, 2002, we adopted the provision
of Emerging Issues Task Force (EITF) Issue 02-3, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities," that requires
certain energy contracts to be shown on a net basis in the income statement (see
Note 1 - "Summary of Significant Accounting Policies" to our financial
statements).
Other Operating Expenses
Other Expenses - Operations - Other increased $5 million in the third
quarter of 2002 and $13 million in the first nine months of 2002, compared to
the same year-ago periods, primarily due to higher injuries and damages expenses
based on claims experience, costs for efficiency improvements made at the coal
plants, increases in employee benefit costs related to the investment
performance of pension plan assets and increasing healthcare costs and a $2
million regulatory fee paid in the third quarter which did not occur in the
prior year. These increases were partially offset by a $2 million decrease in
employee incentive compensation and severance costs earlier in the year. See
"Liquidity and Capital Resources - Outlook" and Item 3 - "Equity Price Risk" for
a discussion of our expectations and plans regarding trends in employee benefit
costs.
Maintenance expenses decreased $1 million in the third quarter of 2002 and
increased $2 million in the first nine months of 2002, compared to the same
year-ago periods. The year to date increase was primarily due to a fire
restoration project at our Hutsonville coal plant coupled with incremental
increases associated with the new combustion turbine generating units added
during the second, third and fourth quarters of 2001.
Depreciation and amortization expense increased $3 million in the third
quarter of 2002 and $12 million in the first nine months of 2002, compared to
the same year-ago periods. This net increase was primarily due to our investment
in new combustion turbine generating units added during the second, third and
fourth quarters of 2001.
Other taxes expense decreased $3 million in the third quarter of 2002 and
$1 million in the first nine months of 2002, compared to the same year-ago
periods, primarily due to adjustments related to revised property tax
assessments in the prior year offset by increased property taxes associated with
the new combustion turbine generating units added in the prior year.
Interest Expense
Interest expense increased $4 million in the third quarter of 2002 and $6
million in the first nine months of 2002, compared to the same year-ago periods,
primarily due to interest associated with the issuance of $275 million of 7.95%
Senior Notes in June 2002 and additional borrowings from the money pool at
higher interest rates prior to the issuance of the Senior Notes. These increases
were partially offset by a reduction in the principal amounts outstanding on our
subordinated intercompany promissory notes to AmerenCIPS and Ameren, therefore
reducing associated interest costs in the current year compared to the prior
year corresponding periods. A significant amount of the proceeds from the Senior
Notes was used to repay lower cost short-term borrowings. Amortization of debt
issuance costs and discounts for the three and nine months ended September 30,
2002 and 2001 of less than $1 million were included in interest expense in the
income statement.
LIQUIDITY AND CAPITAL RESOURCES
Operating
Our net cash flows provided by operating activities decreased $50 million
to $151 million in the first nine months of 2002, compared to the same year-ago
period. Cash provided by operations decreased primarily due to lower net income
and increased funds used in accounts and wages payable compared to the same year
ago period. These decreases were partially offset by an increase in cash flows
from accounts receivable, intercompany due to the timing of receipt of payments
to and from our affiliates.
17
Our gross margins from power supply contracts with affiliated companies
continue to be the principal source of cash from operating activities. We plan
to utilize short-term debt to support normal operations and other temporary
capital requirements. We have the ability to borrow up to $800 million from
Ameren Corporation through a non-utility money pool agreement. However, the
total amount available to us at any time is reduced by the amount of borrowings
from Ameren by our affiliates and is increased to the extent other Ameren
non-regulated companies advance surplus funds to the non-utility money pool or
external borrowing sources are used by Ameren to increase the available amounts.
At September 30, 2002, $800 million was available through the non-utility money
pool not including additional funds available through invested cash balances at
Ameren Corporation and uncommitted bank lines. The non-utility money pool was
established to coordinate and provide for short-term cash and working capital
requirements of Ameren's non-regulated activities and is administered by Ameren
Services. Interest is calculated at varying rates of interest depending on the
composition of internal and external funds in the non-utility money pool. The
average interest rate for borrowings from the non-utility money pool was 8.84%
in the third quarter of 2002 (2001 - 3.66%) and 7.18% for the nine months ended
September 30, 2002 (2001 - 4.68%). We earned less than $1 million in net
intercompany interest income associated with outstanding loans to the
non-utility money pool in the third quarter of 2002 and incurred $5 million in
net intercompany interest expense associated with outstanding borrowings from
the non-utility money pool for the nine months ended September 30, 2002. We
incurred less than $1 million in net intercompany interest expense associated
with outstanding borrowings from the non-utility money pool in the third quarter
of 2001 compared to earning $2 million of net intercompany interest income
associated with outstanding loans to the non-utility money pool for the nine
months ended September 30, 2001. At September 30, 2002, we had loaned $32
million to the non-utility money pool and had no outstanding borrowings.
Our financial agreements include customary default provisions that could
impact the continued availability of credit or result in the acceleration of
repayment. These events include bankruptcy, defaults in payment of other
indebtedness, certain judgments that are not paid or insured, or failure to meet
or maintain covenants. It is also an event of default under the indenture
relating to our outstanding senior notes if one or more payments aggregating $25
million or more due to us from Marketing Company are not made within 60 days of
the date they are due. In addition this indenture includes transitional
covenants that limit our ability to incur indebtedness and pay dividends or make
other specified restricted payments. At September 30, 2002, we were in
compliance with these provisions.
At September 30, 2002, we did not have any off-balance sheet financing
arrangements.
Ameren Corporation made cash contributions totaling $15 million to Ameren's
defined benefit retirement plans during the third quarter of 2002, and Ameren
expects to make additional cash contributions to the plans totaling
approximately $15 million in the fourth quarter of 2002. Our share of the cash
contribution made in the third quarter of 2002 was approximately $1 million, and
we expect our share of the cash contribution that may be made in the fourth
quarter of 2002 will be approximately $1 million. Future funding plans will be
evaluated at the end of 2002. Based on the performance of plan assets through
September 30, 2002, Ameren expects to be required under the Employee Retirement
Income Security Act of 1974 to fund $25 to $50 million in 2004 and $150 to $200
million in 2005 in order to maintain minimum funding levels. We expect our share
of the funding to range between $2 million and $5 million, and $14 million and
$18 million for 2004 and 2005, respectively, plus our share related to employees
of our affiliate, Ameren Services. These amounts are estimates and may change
based on actual stock market performance, changes in interest rates, any plan
funding in 2002 or 2003 and finalization of actuarial assumptions. In addition,
we expect at December 31, 2002 to be required to record a minimum pension
liability that would result in a charge to Other Comprehensive Income (OCI) in
stockholder's equity. The amount of the charge is expected to result in a less
than one percent change in our debt to total capitalization ratios.
Investing
Our cash flows used in investing activities increased $146 million to $300
million for the first nine months of 2002, compared to the same year-ago period,
primarily due to our contribution of excess funds generated by recent financings
to Ameren's non-utility money pool versus our need for these funds in the prior
year. In addition, we had a decrease in construction expenditures for new
combustion turbine generating units and upgrades to existing coal plants in both
periods. Of the $268 million of construction expenditures incurred during the
first nine months of 2002, approximately $140 million was paid to Development
Company for a combustion turbine generating unit purchased in December 2001, but
the amount was included in accounts payable at December 31, 2001 resulting in
approximately $128 million of construction expenditures during the first nine
months of 2002 primarily for the purchase from Development Company of the first
of four combustion turbines at Elgin, Illinois and the selective catalytic
reduction technology added on unit 2 of the Coffeen coal plant.
18
Future Capacity Additions
Of the $300 million of budgeted capital expenditures for 2002, which
excludes the December 2001 purchase referenced above, $222 million relates to
the scheduled purchase from Development Company of four combustion turbine
generating units located in Elgin, Illinois. During the third quarter of 2002,
we acquired one combustion turbine generating unit at Elgin from Development Co.
at historical net book value of approximately $64 million (as noted above). In
October 2002, we acquired two additional combustion turbine generating units at
Elgin from Development Co. The total installed cost of these three units was
approximately $156 million. These units represent 351 megawatts of capacity. We
expect to purchase the fourth combustion turbine generating unit at Elgin by the
end of 2002 which is planned to provide 117 megawatts of additional capacity at
a cost of approximately $50 million. Annual capital expenditures at our coal
plants are expected to range from approximately $225 million to $275 million in
total for the period 2002 through 2006, excluding any capital expenditures
required to comply with NOx emission standards.
To assist our affiliate, AmerenUE, in satisfying its regulatory load
requirements, we propose to transfer to AmerenUE approximately 400 to 500
megawatts of combustion turbine units. The transfer, which will be at net book
value and is subject to receipt of necessary regulatory approvals, is expected
to be completed in the second quarter of 2003. Cash proceeds from the sale will
be applied in accordance with restrictions in the indentures for the notes (to
the extent applicable).
Financing
Our cash flows provided by financing activities were $150 million in the
first nine months of 2002, compared to cash flows used in financing activities
of $44 million in the year-ago comparable period. Our principal financing
activities for 2002 included the issuance of $275 million of 7.95% Senior Notes
due June 1, 2032 to qualified investors under Rule 144A. Interest is payable
semi-annually on June 1 and December 1 of each year, beginning December 1, 2002.
We received net proceeds of $271 million, after debt discount and underwriters'
fees, that were used to reduce short-term borrowings and for general corporate
purposes. In October 2002, we filed a registration statement with the SEC on
Form S-4 to permit an exchange offer of the Senior Notes. Principal payments
made on the AmerenCIPS and Ameren subordinated notes were approximately $43
million (2001 - $40 million) and $4 million (2001 - $4 million) for the nine
months ended September 30, 2002.
Outlook
We currently believe there will be challenges to earnings in 2003 and
beyond due to continued weak energy markets, a soft economy, higher employee
benefit costs and escalating insurance and security costs associated with world
events. These industry-wide trends, coupled with an assumed return to more
normal weather patterns, are expected to put pressure on earnings in 2003 and
beyond. As we complete our analysis of these challenges as part of our overall
budget process, we will be evaluating several initiatives to enhance revenues
and reduce costs for 2003 and beyond. These initiatives may include any or all
of the following:
o Actively managing employee headcount
o Modifying employee benefit plans
o Assessing the necessity of certain plant operations and business support
functions
o Reviewing capital expenditure plans
o Other initiatives
On November 4, 2002, Ameren Corporation announced a voluntary retirement
program that is being offered to approximately 1,000 of its 7,400 employees,
including employees providing support functions to us through Ameren Services
and approximately 85 of our employees. In addition, Ameren announced limits on
its contributions and increased retiree contributions for certain retiree
medical benefit plans and a freeze on wage increases beginning in 2003 for all
management employees, including our management employees. While we and Ameren
expect to realize significant long-term savings as a result of this program, we
expect to incur a one-time, after-tax charge in the fourth quarter of 2002
related to the program. That charge for Ameren could range between $30 million
and $50 million, based on voluntary retirements ranging between 300 and 500,
respectively. We expect to be allocated a portion of the charges depending on
the amount of retirements within our company and Ameren Services. In addition to
the voluntary retirement program, we and Ameren may consider implementing an
involuntary severance program if it is determined that additional positions must
be eliminated to achieve optimum organizational
19
efficiency and effectiveness. Further, we and Ameren will continue to seek other
ways to reduce staffing over the next year to reduce costs and gain efficiencies
in operations.
In the ordinary course of business, we evaluate several strategies to
enhance our financial position, earnings and liquidity. These strategies may
include potential acquisitions, divestitures, opportunities to reduce costs or
increase revenues, and other strategic initiatives in order to increase
shareholder value. We are unable to predict which, if any, of these initiatives
will be executed, as well as the impact these initiatives may have on our future
financial position, results of operations or liquidity.
Electric Industry Restructuring and Regulatory Matters
Illinois
See Note 2 - "Rate and Regulatory Matters" to our financial statements.
Federal - Electric Transmission
See Note 2 - "Rate and Regulatory Matters" to our financial statements.
ACCOUNTING MATTERS
Critical Accounting Policies
Preparation of the financial statements and related disclosures in
compliance with generally accepted accounting principles requires the
application of appropriate technical accounting rules and guidance, as well as
the use of estimates. Our application of these policies involves judgments
regarding many factors, which, in and of themselves, could materially impact the
financial statements and disclosures. A future change in the assumptions or
judgments applied in determining the following matters, among others, could have
a material impact on future financial results. In the table below, we have
outlined those accounting policies that we believe are most difficult,
subjective or complex:
Accounting Policy Uncertainties Affecting Application
- ----------------- -----------------------------------
Environmental Costs
We accrue for all known environmental o Extent of contamination
contamination where remediation can be o Responsible party determination
reasonably estimated. However, we are o Approved methods for cleanup
contractually indemnified by AmerenCIPS for o Present and future legislation and governmental
remediation costs that we incur at the sites of regulations and standards
our coal plants relating to environmental o Results of ongoing research and development
contamination that occurred prior to the regarding environmental impacts
AmerenCIPS' transfer of the coal plants to us on
May 1, 2000.
Basis for Judgment
We determine the proper amounts to accrue for environmental contamination based on internal and third
party estimates of clean-up costs in the context of current remediation regulation standards and available
technology.
20
Benefit Plan Accounting
Based on actuarial calculations, we accrue costs o Future rate of return on pension and other plan
of providing future employee benefits in assets
accordance with SFAS 87, 106 and 112. See Note o Interest rates used in valuing benefit
6 to our financial statements for the year ended obligations
December 31, 2001. o Healthcare cost trend rates
Basis for Judgment
We utilize a third party consultant to assist us in evaluating and recording the proper amount for future
employee benefits. Our ultimate selection of the discount rate, healthcare trend rate and expected rate of
return on pension assets is based on our review of available current, historical and projected rates, as
applicable.
Derivative Financial Instruments
We record all derivatives at their fair market o Market conditions in the energy industry,
value in accordance with SFAS 133. The especially the effects of price volatility on
identification and classification of a contractual commodity commitments
derivative, and the fair value of such o Regulatory and political environments and
derivative must be determined. See Note 3 to requirements
our financial statements for the year ended o Fair value estimations on longer term contracts
December 31, 2001 and Note 4 - "Derivative
Financial Instruments" to our financial
statements in this report.
Basis for Judgment
We determine whether a transaction is a derivative versus a normal purchase or sale based on historical
practice and our intention at the time we enter a transaction. We utilize actively quoted prices, prices
provided by external sources, and prices based on internal models, and other valuation methods to
determine the fair market value of derivative financial instruments.
Impact of Future Accounting Pronouncements
See Note 1 - "Summary of Significant Accounting Policies" to our financial
statements.
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, etc.). The following discussion of our
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. AmerenEnergy and Fuels Company,
on our behalf, manages our market risks in accordance with established policies,
which may include entering into various derivative transactions. In the normal
course of business, we also face risks that are either non-financial or
non-quantifiable. Such risks principally include business, legal and operational
risk and are not represented in the following analysis.
Our risk management objective is to optimize our physical generating assets
within prudent risk parameters. Our risk management policies are set by a Risk
Management Steering Committee, which is comprised of senior-level Ameren
officers.
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated
with our issuance of both variable rate and fixed rate debt. We manage our
interest rate exposure by controlling the amount of these instruments we hold
within our total capitalization portfolio and by monitoring the effects of
market changes in interest rates. At September 30, 2002, we had no variable rate
non-utility money pool borrowings outstanding.
21
Fuel Price Risk
100% of the required 2002 and 95% of the required 2003 supply of coal for
our coal plants has been acquired at fixed prices. As such, we have minimal coal
price risk for the remainder of 2002 or 2003. Approximately 72% of our coal
requirements for 2003 through 2006 are covered by contracts.
Fair Value of Contracts
We utilize derivatives principally to manage the risk of changes in market
prices for natural gas, fuel, electricity and emission credits. Price
fluctuations in natural gas, fuel and electricity cause:
o an unrealized appreciation or depreciation of our firm commitments to
purchase or sell when purchase or sale prices under the firm commitment are
compared with current commodity prices;
o market values of fuel and natural gas inventories or purchased power to
differ from the cost of those commodities in inventory and under firm
commitment; and
o actual cash outlays for the purchase of these commodities to differ from
anticipated cash outlays.
The derivatives that we use to hedge these risks are dictated by risk
management policies and include forward contracts, futures contracts, options
and swaps. We continually assess our supply and delivery commitment positions
against forward market prices and internally forecast forward prices and modify
our exposure to market, credit and operational risk by entering into various
offsetting transactions. In general, we believe these transactions serve to
reduce our price risk. See Note 4 - "Derivative Financial Instruments" to our
financial statements for more information.
The following summarizes changes in the fair value of all contracts marked
to market during the three and nine months ended September 30, 2002:
- -------------------------------------------------------------------------------------------------------------------
Three Nine
months months
- -------------------------------------------------------------------------------------------------------------------
Fair value of contracts at beginning of period, net $ (a) $ 2
Contracts which were realized or otherwise settled during the period (a) (2)
Changes in fair values attributable to changes in valuation techniques and assumptions --- ---
Fair value of new contracts entered into during the period (a) (a)
Other changes in fair value (a) (a)
- -------------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at September 30, 2002, net $ (a) $ (a)
- -------------------------------------------------------------------------------------------------------------------
(a) Less than $1 million.
Maturities of contracts as of September 30, 2002 were as follows:
- -------------------------------------------------------------------------------------------------------------------
Maturity Maturity
less than Maturity Maturity in excess Total fair
Sources of fair value 1 year 1-3 years 4-5 years of 5 years value (a)
- ------------------------------------------------------------------------------------------------------------------
Prices actively quoted $ --- $ --- $ --- $ --- $ ---
Prices provided by other external
sources (b) (d) --- --- --- (d)
Prices based on models and other
valuation methods (c) (d) (d) --- --- (d)
- ------------------------------------------------------------------------------------------------------------------
Total $ (d) $ (d) $ --- $ --- $ (d)
- ------------------------------------------------------------------------------------------------------------------
(a) Contracts valued at less than $1 million were with both investment grade
and non-investment-grade rated counterparties.
(b) Principally power forward values based on NYMEX prices for over-the-counter
contracts.
(c) Principally power forwards and SO2 options valued based on information from
external sources and our estimates.
(d) Less than $1 million.
22
Equity Price Risk
We, along with other subsidiaries of Ameren, are a participant in Ameren's
defined benefit plans and postretirement benefit plans and are responsible for
our proportional share of the costs. Ameren's costs of providing
non-contributory defined benefit retirement and postretirement benefit plans are
dependent upon a number of factors, such as the rates of return on plan assets,
discount rate, the rate of increase in health care costs and contributions made
to the plans. The market value of Ameren's plan assets has been affected by
declines in the equity market since 2001 and 2000 for the pension and
postretirement plans. As a result, at December 31, 2002, Ameren and its
subsidiaries, including us, could be required to recognize an additional minimum
pension liability as prescribed by SFAS No. 87, "Employers' Accounting for
Pensions" and SFAS No. 132, "Employers' Disclosures about Pensions and
Postretirement Benefits." The liability would be recorded as a reduction to OCI
and would not affect net income for 2002. The amount of the liability will
depend upon asset returns experienced in 2002, changes in interest rates and
Ameren's contributions to the plans during 2002. The liability recorded and cash
contributions to the plans could be material in future years without a
substantial recovery in equity markets. If the fair value of the plan assets
were to grow and exceed the accumulated benefit obligations in the future, then
the recorded liability would be reduced and a corresponding amount of OCI would
be restored in the Balance Sheet. See "Liquidity and Capital Resources -
Operating" and Note 1 - "Summary of Significant Accounting Policies" to our
financial statements.
ITEM 4. Controls and Procedures
Within the 90 days prior to the date of this report, we carried out an
evaluation, under the supervision and with participation of our management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13a-14 under the Securities Exchange Act of 1934, as
amended. Based upon that evaluation, the Chief Executive Officer and Chief
Financial Officer concluded that our disclosure controls and procedures are
effective in timely alerting them to material information relating to
AmerenEnergy Generating Company which is required to be included in our periodic
SEC filings.
There have been no significant changes in our internal controls or in other
factors which could significantly affect internal controls subsequent to the
date we carried out our evaluation.
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, events, conditions and
financial performance. In connection with the "safe harbor" provisions of the
Private Securities Litigation Reform Act of 1995, we are 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 2001 Annual
Report on Form 10-K for the year ended December 31, 2001, and in subsequent
securities filings, could cause results to differ materially from management
expectations as suggested by such "forward-looking" statements:
o the effects of the stipulation and agreement relating to the AmerenUE's
Missouri electric excess earnings complaint case and other regulatory
actions, including changes in regulatory policy;
o changes in laws and other governmental actions, including monetary and
fiscal policies;
o the impact on us of current regulations related to the opportunity for
customers to choose alternative energy suppliers in Illinois;
o the effects of increased competition in the future;
o the effects of Ameren's participation in a FERC approved Regional
Transmission Organization (RTO), including activities associated with the
Midwest Independent System Operator;
o availability and future market prices for fuel and purchased power,
electricity and natural gas, including the use of financial and derivative
instruments and volatility of changes in market prices;
o wholesale and retail pricing for electricity in the Midwest;
o business and economic conditions;
23
o the impact of the adoption of new accounting standards on the application
of appropriate technical accounting rules and guidance;
o interest rates and the availability of capital;
o actions of rating agencies and the effects of such actions;
o weather conditions;
o generation plant construction, installation and performance;
o the effects of strategic initiatives, including acquisitions and
divestitures;
o the impact of current environmental regulations on generating companies and
the expectation that more stringent requirements will be introduced over
time, which could potentially have a negative financial effect;
o future wages and employee benefits costs, including changes in returns of
benefit plan assets;
o disruptions of the capital markets or other events making Ameren's and our
access to necessary capital more difficult or costly;
o competition from other generating facilities including new facilities that
may be developed in the future;
o cost and availability of transmission capacity for the energy generated by
our generating facilities or required to satisfy energy sales made on our
behalf; and
o legal and administrative proceedings.
Given these uncertainties, undue reliance should not be placed on these
forward-looking statements. Except to the extent required by the federal
securities laws, we undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
24
PART II. OTHER INFORMATION
ITEM 5. Other Information
Reference is made to Item 5. Other Information in Part II of our Form 10-Q
for the quarterly period ended June 30, 2002 for a listing of the audit and
non-audit services that the Auditing Committee of the Ameren Board of Directors
has pre-approved for performance by our independent accountants,
PricewaterhouseCoopers LLP. At its October 2002 meeting, the Auditing Committee
also pre-approved PricewaterhouseCoopers LLP to perform audits of two coal
supply contracts of our affiliate, Union Electric Company, operating as AmerenUE
with respect to the handling of prepaid reclamation funds.
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits.
99.1 - Certificate of Chief Executive Officer required by Section 906
of the Sarbanes-Oxley Act of 2002.
99.2 - Certificate of Chief Financial Officer required by Section 906
of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K. None.
Note: Reports of Ameren Corporation on Forms 8-K, 10-Q and 10-K are on
file with the SEC under File Number 1-14756.
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.
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.
SIGNATURE
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 ENERGY GENERATING COMPANY
(Registrant)
By /s/ Martin J. Lyons
------------------------------
Martin J. Lyons
Controller
(Principal Accounting Officer)
Date: November 14, 2002
25
CERTIFICATIONS
I, Daniel F. Cole, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Ameren
Energy Generating Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this quarterly
report;
4. The registrant's other certifying officers and I are responsible
for establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated
in this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 14, 2002 /s/ Daniel F. Cole
-------------------------
Daniel F. Cole
Chief Executive Officer
26
I, Warner L. Baxter, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Ameren
Energy Generating Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this quarterly
report;
4. The registrant's other certifying officers and I are responsible
for establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and
report financial data and have identified for the
registrant's auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated
in this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 14, 2002 /s/ Warner L. Baxter
------------------------
Warner L. Baxter
Chief Financial Officer
27