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 June 30, 2003
[ ] 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 ( ).
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ( ). No (X).
Shares outstanding of the registrant's common stock as of August 14, 2003:
Common Stock, no par value, held by AmerenEnergy Development Company (parent
company of the registrant and indirect subsidiary of Ameren Corporation) -
2,000.
OMISSION OF CERTAIN INFORMATION
The Registrant meets the conditions set forth in General Instruction
(H)(1)(a) and (b) of Form 10-Q as a wholly owned indirect subsidiary of Ameren
Corporation and is therefore filing this Form 10-Q with the reduced disclosure
format allowed under that General Instruction.
AMEREN ENERGY GENERATING COMPANY
TABLE OF CONTENTS
Page
----
PART I. Financial Information
ITEM 1. Financial Statements (Unaudited)
Balance Sheet at June 30, 2003 and December 31, 2002...................................................... 1
Statement of Income for the three and six months ended June 30, 2003 and 2002............................. 2
Statement of Cash Flows for the six months ended June 30, 2003 and 2002................................... 3
Statement of Common Stockholder's Equity for the three and six months ended
June 30, 2003 and 2002.................................................................................... 4
Notes to Financial Statements............................................................................. 5
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..................... 13
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk................................................ 19
ITEM 4. Controls and Procedures................................................................................... 21
Forward-Looking Statements................................................................................ 21
PART II. Other Information
ITEM 1. Legal Proceedings.......................................................................................... 23
ITEM 5. Other Information.......................................................................................... 24
ITEM 6. Exhibits and Reports on Form 8-K........................................................................... 24
SIGNATURE..................................................................................................................... 25
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 Part I under the heading
"Forward-Looking Statements." 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.
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
AMEREN ENERGY GENERATING COMPANY
BALANCE SHEET
(Unaudited, in millions, except shares)
June 30, December 31,
2003 2002
----------------- ---------------
ASSETS:
Property and plant, net $ 1,780 $ 1,767
Current assets:
Cash and cash equivalents 8 3
Accounts receivable 9 10
Accounts receivable - intercompany 73 68
Other receivables - 2
Materials and supplies, at average cost -
Fossil fuel 68 50
Other 24 27
Taxes receivable - 71
Other 1 -
----------------- ---------------
Total current assets 183 231
Other 13 12
----------------- ---------------
Total Assets $ 1,976 $ 2,010
================= ===============
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 178 131
Accumulated other comprehensive income (loss) (1) (1)
----------------- ---------------
Total common stockholder's equity 327 280
----------------- ---------------
Subordinated notes payable - intercompany 358 412
Long-term debt 698 698
----------------- ---------------
Total capitalization 1,383 1,390
----------------- ---------------
Current liabilities:
Current portion of subordinated notes payable - intercompany 53 50
Accounts and wages payable 35 55
Accounts and wages payable - intercompany 22 32
Asset retirement obligation 4 -
Notes payable - intercompany 154 191
Current portion of income taxes payable - intercompany 13 13
Interest payable 8 8
Interest payable - intercompany 8 7
Taxes accrued 7 -
Other 3 2
----------------- ---------------
Total current liabilities 307 358
----------------- ---------------
Deferred income taxes, net 94 66
Accumulated deferred investment tax credits 14 15
Income tax payable - intercompany 156 162
Other deferred credits and liabilities 22 19
----------------- ---------------
Total Capital and Liabilities $ 1,976 $ 2,010
================= ===============
See Notes to Financial Statements.
1
AMEREN ENERGY GENERATING COMPANY
STATEMENT OF INCOME
(Unaudited, in millions)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------- ----------------------------
2003 2002 2003 2002
------------- ------------- ------------- -------------
OPERATING REVENUES:
Electric - intercompany $ 151 $ 157 $ 319 $ 314
Electric 19 15 54 32
Other - intercompany 3 3 6 6
------------- ------------- ------------- -------------
Total operating revenues 173 175 379 352
------------- ------------- ------------- -------------
OPERATING EXPENSES:
Fuel and purchased power 72 79 160 158
Other operations and maintenance 35 47 70 84
Depreciation and amortization 19 17 37 33
Other taxes 6 6 13 12
------------- ------------- ------------- -------------
Total operating expenses 132 149 280 287
------------- ------------- ------------- -------------
OPERATING INCOME 41 26 99 65
OTHER INCOME AND (DEDUCTIONS):
Miscellaneous, net -
Miscellaneous income - - 2 -
------------- ------------- ------------- -------------
Total other income and (deductions) - - 2 -
------------- ------------- ------------- -------------
INTEREST CHARGES:
Interest expense - intercompany 11 12 23 22
Interest expense 14 10 28 18
------------- ------------- ------------- -------------
Total interest charges 25 22 51 40
------------- ------------- ------------- -------------
INCOME BEFORE INCOME TAXES 16 4 50 25
INCOME TAXES 6 2 19 10
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE 10 2 31 15
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES - - 18 -
------------- ------------- ------------- -------------
NET INCOME $ 10 $ 2 $ 49 15
============= ============= ============= =============
See Notes to Financial Statements.
2
AMEREN ENERGY GENERATING COMPANY
STATEMENT OF CASH FLOWS
(Unaudited, in millions)
Six Months Ended
June 30,
---------------------
2003 2002
--------- ---------
Cash Flows From Operating:
Net income $ 49 $ 15
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting principle (18) -
Depreciation and amortization 37 33
Deferred income taxes, net 27 11
Deferred investment tax credits, net (1) (1)
Other - (1)
Changes in assets and liabilities:
Accounts receivable 1 (4)
Accounts receivable - intercompany (3) 50
Materials and supplies (15) 2
Taxes receivable, net 66 4
Accounts and wages payable (7) (17)
Accounts and wages payable - intercompany (10) (11)
Current portion of income taxes payable-intercompany (6) (11)
Interest payable - 1
Interest payable - intercompany 1 5
Assets, other - (16)
Liabilities, other 5 8
--------- ---------
Net cash provided by operating activities 126 68
--------- ---------
Cash Flows Used In Investing:
Construction expenditures (31) (190)
Notes receivable - intercompany - (33)
--------- ---------
Net cash used in investing activities (31) (223)
--------- ---------
Cash Flows From Financing:
Dividends paid to Ameren Corporation (2) (2)
Debt issuance costs - (3)
Redemptions:
Notes payable - intercompany (37) (62)
Subordinated notes payable - intercompany (51) (46)
Issuances:
Notes payable - intercompany - 274
--------- ---------
Net cash (used in) provided by financing activities (90) 161
--------- ---------
Net change in cash and cash equivalents 5 6
Cash and cash equivalents at beginning of year 3 2
--------- ---------
Cash and cash equivalents at end of period $ 8 $ 8
========= =========
Cash paid during the periods:
Interest - intercompany $ 21 $ 16
Interest 28 17
Income taxes - 4
See Notes to Financial Statements.
3
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF COMMON STOCKHOLDER'S EQUITY
(Unadutied in millions, except shares)
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------- --------------------------
2003 2002 2003 2002
--------------------------- --------------------------
Common stock $ - $ - $ - $ -
Other paid-in capital
Beginning balance 150 150 150 150
Change in current period - - - -
------------ ------------- ------------ ------------
150 150 150 150
------------ ------------- ------------ ------------
Retained earnings
Beginning balance 169 132 131 120
Net income 10 2 49 15
Dividends paid to Ameren (1) (1) (2) (2)
------------ ------------- ------------ ------------
178 133 178 133
------------ ------------- ------------ ------------
Accumulated other comprehensive income
Beginning balance 5 2 5 4
Change in derivative financial instruments in current period - 1 - (1)
------------ ------------- ------------ ------------
5 3 5 3
------------ ------------- ------------ ------------
Beginning balance - minimum pension liability (6) - (6) -
Change in minimum pension liability in current period - - - -
------------ ------------- ------------ ------------
(1) 3 (1) 3
------------ ------------- ------------ ------------
Total common stockholder's equity $ 327 $ 286 $ 327 $ 286
============ ============= ============ ============
Comprehensive income, net of taxes
Net income $ 10 $ 2 $ 49 $ 15
Unrealized net gain/(loss) on derivative hedging instruments,
net of income taxes of $-, $-, $-, and $-, respectively - 1 - -
Reclassification adjustments for gains/(losses) included in net income
net of income taxes of $-, $1-, $-, and $(1), respectively - - - (1)
------------ ------------- ------------ ------------
Total comprehensive income, net of taxes $ 10 $ 3 $ 49 $ 14
============ ============= ============ ============
See Notes to Financial Statements.
4
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
June 30, 2003
NOTE 1 - Summary of Significant Accounting Policies
General
AmerenEnergy Generating Company, headquartered in St. Louis, Missouri, is
an indirect wholly-owned subsidiary of Ameren Corporation (Ameren). We own and
operate a wholesale electric generation business in Illinois and Missouri. 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,
all related fuel, supply, transportation, maintenance and labor agreements,
approximately 45% of AmerenCIPS' employees, and other related rights, assets and
liabilities.
Ameren is a public utility holding company registered with the Securities
and Exchange Commission (SEC) under the Public Utility Holding Company Act of
1935 (PUHCA) and is headquartered in St. Louis, Missouri. Ameren's 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. Ameren's principal subsidiaries
and our affiliates are as follows:
o Union Electric Company, which operates a rate-regulated electric
generation, transmission and distribution business, and a rate-regulated
natural gas distribution business in Missouri and Illinois as AmerenUE.
o AmerenCIPS, which operates a rate-regulated electric and natural gas
transmission and distribution business in Illinois.
o Central Illinois Light Company, a subsidiary of CILCORP Inc. (CILCORP),
which operates a rate-regulated transmission and distribution business, an
electric generation business, and a rate-regulated natural gas distribution
business in Illinois as AmerenCILCO. Ameren completed its acquisition of
CILCORP on January 31, 2003.
o AmerenEnergy Resources Company (Resources Company), which consists of non
rate-regulated operations. Subsidiaries include us, AmerenEnergy Marketing
Company (Marketing Company), which markets power for periods primarily over
one year, AmerenEnergy Fuels and Services Company (Fuels Company), which
procures fuel and manages the related risks for us and our affiliates,
AmerenEnergy Development Company (Development Company), which, as our
parent, develops and constructs generating facilities for us, and
AmerenEnergy Medina Valley Cogen (No. 4), LLC, which indirectly owns a 40
megawatt, gas-fired electric generation plant. On February 4, 2003, Ameren
completed its acquisition of AES Medina Valley Cogen (No. 4), LLC (Medina
Valley) and renamed it AmerenEnergy Medina Valley Cogen (No. 4), LLC.
o AmerenEnergy, Inc. (AmerenEnergy), which serves as a power marketing and
risk management agent for us and our affiliates for transactions of
primarily less than one year.
o Electric Energy, Inc. (EEI), which 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 Ameren and its subsidiaries, including us. Charges are based
upon the actual costs incurred by Ameren Services, as required by the
PUHCA.
When we refer to our, we, us or Generating Company, 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.
The accounting policies of Generating Company conform to generally accepted
accounting principles in the United States (GAAP). Our financial statements
reflect all adjustments (which include normal, recurring adjustments) necessary,
in our opinion, for a fair presentation of our interim results. These statements
should be read in conjunction with the financial statements and the notes
thereto included in our 2002 Annual Report on Form 10-K.
The preparation of financial statements in conformity with GAAP requires
management to make certain estimates and assumptions. Such estimates and
assumptions affect reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of
5
revenues and expenses during the reported period. Actual results could differ
from those estimates. Certain reclassifications have been made to prior years'
financial statements to conform to 2003 reporting.
Accounting Changes and Other Matters
Statement of Financial Accounting Standards (SFAS) No. 143 - "Accounting for
Asset Retirement Obligations"
We adopted the provisions of SFAS 143 effective January 1, 2003. SFAS 143
provides the accounting requirements for asset retirement obligations associated
with tangible, long-lived assets. SFAS 143 requires us to record the estimated
fair value of legal obligations associated with the retirement of tangible
long-lived assets in the period in which the liabilities are incurred and to
capitalize a corresponding amount as part of the book value of the related
long-lived asset. In subsequent periods, we are required to adjust asset
retirement obligations based on changes in estimated fair value. Corresponding
increases in asset book values are depreciated over the remaining useful life of
the related asset. Uncertainties as to the probability, timing or amount of cash
flows associated with an asset retirement obligation affect our estimate of fair
value.
Upon adoption of this standard, we recognized an asset retirement
obligation of approximately $4 million and a net increase in net property and
plant of approximately $34 million. The asset retirement obligation relates to
retirement costs for a power plant ash pond. The net increase in net property
and plant, as well as the majority of the net after-tax gain of $18 million we
recognized upon adoption, resulted from the elimination of non-legal obligation
costs of removal previously accrued as a component of accumulated depreciation
($20 million). We also recognized a loss for the difference between the net
asset and liability for the retirement obligation recorded upon adoption related
to our assets ($2 million).
In addition to those obligations that were identified and valued, we
determined that certain other asset retirement obligations exist. However, we
are unable to estimate the fair value of those obligations because the
probability, timing or cash flows associated with the obligations are
indeterminable. We do not believe that these obligations, when incurred, will
have a material adverse impact on our financial position, results of operations
or liquidity.
SFAS 143 required a change in the depreciation methodology we historically
utilized for our operations. Historically, we included an estimated cost of
dismantling and removing plant from service upon retirement in the basis upon
which our depreciation rates were determined. SFAS 143 required us to exclude
costs of dismantling and removal upon retirement from the depreciation rates
applied to our plant balances. Further, we were required to remove accumulated
provisions for dismantling and removal costs from accumulated depreciation,
where they were embedded, and reflect such adjustment as a gain upon adoption of
this standard, to the extent such dismantling and removal activities are not
considered legal asset retirement obligations as defined by SFAS 143. The
elimination of cost of removal from accumulated depreciation resulted in a gain,
as noted above, of $20 million, net of taxes, for a change in accounting
principle. Beginning in January 2003, depreciation rates for our assets were
reduced to reflect the discontinuation of the accrual of dismantling and removal
costs. In addition, our asset removal costs will prospectively be expensed as
incurred. As a result, the impact of this change in accounting will result in a
decrease in depreciation expense and an increase in operations and maintenance
expense, the net impact of which is indeterminable, but not expected to be
material.
Emerging Issues Task Force (EITF) Issue No. 02-3 and EITF Issue No. 98-10
In the quarters ended September 30, 2002 and December 31, 2002, we adopted
the provisions of EITF 02-3, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and 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 adopting EITF 02-3 and the rescission of EITF 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities," 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
- - Electric and in Operating Expenses - Fuel and Purchased Power. This meant that
revenues were recorded for the sum of the contract notional amounts of the power
sales contracts with a corresponding charge to income for the costs of the
energy that was generated, or for the sum of the contract notional amounts of a
purchased power contract.
In October 2002, the EITF reached a consensus to rescind EITF 98-10. The
effective date for the full rescission of EITF 98-10 was for fiscal periods
beginning after December 15, 2002, with early adoption permitted. In addition,
the EITF reached a consensus in October 2002 that all SFAS No. 133 ("Accounting
for Derivative Instruments and Hedging Activities") trading derivatives
(subsequent to the rescission of EITF 98-10) should be shown net in the
6
income statement, whether or not physically settled. This consensus applies to
all energy and non-energy related trading derivatives that meet the definition
of a derivative pursuant to SFAS 133. The operating revenues and costs that were
netted for the three and six months ended June 30, 2002 were $44 million and
$131 million, respectively, which reduced Electric Revenues and Fuel and
Purchased Power by equal amounts. The adoption of EITF 02-3, the rescission of
EITF 98-10 and the related transition guidance resulted in netting of energy
contracts and lowered our reported revenues and costs with no impact on
earnings.
SFAS No. 149 - "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities"
In April 2003, the FASB issued SFAS 149. SFAS 149 clarifies under what
circumstances a contract with initial net investment meets the characteristics
of a derivative as discussed in SFAS 133, "Accounting for Derivative Instruments
and Hedging Activities." SFAS 149 is effective for hedging relationships
designated and contracts entered into or modified after June 30, 2003. We do not
expect SFAS 149 to have any impact on our financial position, results of
operations or liquidity upon adoption in the third quarter of 2003.
SFAS No. 150 - "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150 that established standards for how an
issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. SFAS 150 requires financial
instruments that were issued in the form of shares with an unconditional
obligation, where the issuer must redeem the instrument by transferring its
assets on a specified date, be classified as liabilities. Accordingly, SFAS 150
requires issuers to classify mandatorily redeemable financial instruments as
liabilities. SFAS 150 also requires such financial instruments to be measured at
fair value and a cumulative effect adjustment to be recognized in the statement
of income for any difference between the carrying amount and fair value.
SFAS 150 will be effective in the third quarter of 2003. At this time, we
do not expect SFAS 150 to have any impact on our financial position, results of
operations and liquidity upon adoption in the third quarter of 2003.
FASB Interpretation No. (FIN) 46 - "Consolidation of Variable Interest Entities,
an Interpretation of Accounting Research Bulletin (ARB) No. 51, Consolidated
Financial Statements"
The FASB issued FIN 46 in January 2003. FIN 46 provides guidance on the
identification of, and financial reporting for, entities over which control is
achieved through means other than voting rights; such entities are known as
variable-interest entities (VIEs). FIN 46 will determine the following:
o Whether consolidation is required under the "controlling financial
interest" model of ARB 51, or other existing authoritative guidance;
o Or, alternatively, whether the variable-interest model under FIN 46
should be used to account for existing and new entities.
The initial application of FIN 46 depends on the date that the VIE was
created. For public entities, FIN 46 is effective no later than the beginning of
the first interim period that starts after June 15, 2003. At this time, we are
assessing the impact of FIN 46 on our financial position, results of operations,
or liquidity upon adoption in the third quarter of 2003.
Interchange Revenues
Interchange revenues included in Operating Revenues - Electric were $19
million and in Operating Revenues - Electric - Intercompany were $8 million for
the three months ended June 30, 2003 (2002 - $15 million in Operating Revenues -
Electric and $9 million in Operating Revenues - Electric - Intercompany).
Interchange revenues included in Operating Revenues - Electric were $54 million
and in Operating Revenues - Electric - Intercompany were $19 million for the six
months ended June 30, 2003 (2002 - $19 million in Operating Revenues - Electric
and $18 million in Operating Revenues - Electric - Intercompany).
Purchased Power
Purchased power included in Operating Expenses - Fuel and Purchased Power
was $30 million for the three months ended June 30, 2003 (2002 - $24 million)
and $71 million for the six months ended June 30, 2003 (2002 - $52 million).
7
Pension
At December 31, 2002, Ameren recorded a minimum pension liability of $102
million, after taxes, which resulted in a charge to Accumulated Other
Comprehensive Income (Loss) (OCI) and a reduction in stockholders' equity. Our
share of the minimum pension liability was approximately $6 million, after
taxes. Based on changes in interest rates, Ameren may need to change its
actuarial assumptions for its pension plan at December 31, 2003, which could
result in a requirement to record an additional minimum pension liability.
NOTE 2 - Rate and Regulatory Matters
Intercompany Transfer of Electric Generating Facilities and Illinois Service
Territory
As a part of the settlement of the Missouri electric rate case in 2002,
AmerenUE committed to making certain infrastructure investments from January 1,
2002 through June 30, 2006. These requirements are expected to be satisfied in
part by our proposed sale at net book value (approximately $260 million) to
AmerenUE of approximately 550 megawatts of combustion turbine generating units
at Pinckneyville and Kinmundy, Illinois. The sale is subject to receipt of
necessary regulatory approvals. Approval by the Missouri Public Service
Commission (MoPSC) is not required in order for this sale to occur. However, the
MoPSC has jurisdiction over AmerenUE's ability to recover the cost of the
purchased generating facilities from its electric customers in its rates. As a
part of the settlement of the Missouri electric rate case in 2002, AmerenUE is
subject to a rate moratorium providing for no changes in electric rates before
June 30, 2006, subject to certain statutory and other exceptions.
In February 2003, AmerenUE sought approval from the Federal Energy
Regulatory Commission (FERC) and the Illinois Commerce Commission (ICC) to
purchase 550 megawatts of generating assets from us. Several independent power
producers have objected to AmerenUE's request to the FERC based on a claim that
the sale may harm competition for the sale of electricity at wholesale. In April
2003, NRG Energy Inc. (NRG) and some of its affiliates filed testimony in the
ICC proceeding contending that NRG's 640 megawatt generating facility at
Vandalia, Missouri, known as the Audrain Facility, was a better resource for
AmerenUE to acquire as compared to our Kinmundy and Pinckneyville combustion
turbine generating units. In addition, the ICC Staff filed testimony that
expressed concerns about whether the sale is the least cost generating resource
for AmerenUE, and recommended that the ICC deny approval of the sale.
On May 5, 2003, the FERC issued an order which set for hearing the effect
of the proposed sale on competition in wholesale electric markets. On June 4,
2003, AmerenUE filed a Motion for Reconsideration of this order contending that
the FERC erred in setting this matter for hearing. On June 10, 2003, AmerenUE
filed direct testimony with the FERC in support of the proposed sale. On August
8, 2003, two intervenors, NRG and The Electric Power Supply Association, filed
testimony opposing the proposed purchase.
On May 30, 2003, AmerenUE filed a Notice of Withdrawal with the ICC stating
that AmerenUE elected not to pursue approval of the sale and was withdrawing its
request. In the Notice, AmerenUE stated that the concerns expressed by the ICC
Staff regarding AmerenUE's means of satisfying its generating capacity needs, as
well as the MoPSC's views of the appropriate means of meeting generating
capacity obligations, have demonstrated to AmerenUE the difficulty of a single
company operating as an electric utility in both a regulated generation
jurisdiction such as Missouri and an unregulated generation jurisdiction such as
Illinois. To remedy this difficulty, AmerenUE announced in the Notice its plan
to limit its public utility operations to the State of Missouri and to
discontinue operating as a public utility subject to ICC regulation. AmerenUE
intends to accomplish this plan by transferring its Illinois-based electric and
natural gas businesses, including its Illinois-based distribution assets and
certain of its transmission assets, to AmerenCIPS. AmerenUE's electric
generating facilities and certain of its electric transmission facilities in
Illinois would not be part of the transfer. The transfer of AmerenUE's
Illinois-based utility businesses will require the approval of the ICC, the
FERC, the MoPSC and the SEC under the provisions of the PUHCA. On June 13, 2003,
the ICC Staff filed a response to AmerenUE's Notice of Withdrawal indicating
that the ICC Staff did not object to it and on July 23, 2003, the ICC issued an
order accepting the withdrawal. In the third quarter of 2003, AmerenUE expects
to file with the MoPSC, the ICC, the FERC and the SEC for authority to transfer
AmerenUE's Illinois-based utility businesses, at net book value, to AmerenCIPS.
Upon receipt of regulatory approvals and completion of the transfer of
AmerenUE's Illinois-based utility businesses, the ICC's approval will no longer
be required for the sale of the Pinckneyville and Kinmundy combustion turbine
generating units by us to AmerenUE. We intend to continue with the sale of these
electric generating facilities and will continue to seek approvals from
regulators having jurisdiction over the transaction.
8
FERC approval of the transaction is needed, and because the transaction does not
require state regulatory approval, SEC approval under the PUHCA is also
required.
We are unable to predict the ultimate outcome of these regulatory
proceedings or the timing of the final decisions of the various agencies. As a
result, we are not able at this time to estimate the impact of these
transactions on our financial position, results of operations or liquidity.
Regional Transmission Organization (RTO)
Since April 2002, AmerenUE, AmerenCIPS and subsidiaries of FirstEnergy
Corporation and NiSource Inc. (collectively the GridAmerica Companies) have
participated in a number of filings at the FERC in an effort to form GridAmerica
LLC as an independent transmission company (ITC). On December 19, 2002, the FERC
issued an order conditionally approving the formation and operation of
GridAmerica as an ITC within the Midwest Independent System Operator (Midwest
ISO), subject to further compliance filings.
In response to the December 19, 2002 order, the GridAmerica Companies made
three additional filings at the FERC. On January 31, 2003 the GridAmerica
Companies filed a request for authorization to transfer functional control of
certain transmission assets to GridAmerica. On February 18, 2003, the
GridAmerica Companies filed revised agreements codifying the formation and
operation of GridAmerica to reflect changes requested by the FERC in the
December 19, 2002 order. On February 28, 2003, the GridAmerica Companies
together with the Midwest ISO filed revisions to the Midwest ISO Open Access
Transmission Tariff (OATT) to provide rates for service over the transmission
facilities to be transferred to GridAmerica by the GridAmerica Companies.
On April 30 2003, the FERC issued orders in response to the January 31,
2003 and February 28, 2003 filings. In its order regarding the GridAmerica
Companies' request to transfer functional control of their transmission assets
to GridAmerica, the FERC authorized the transfer. In response to the February
28, 2003 filing, the FERC accepted the amendments to the Midwest ISO OATT
effective upon the commencement of service over the GridAmerica transmission
facilities under the Midwest ISO OATT, suspended the proposed rates for a
nominal period, subject to refund, and established hearing and settlement
procedures to determine the justness and reasonableness of the proposed rate
amendments to the Midwest ISO OATT. At this time, the parties are pursuing
settlement of the disputed rate issues. Absent settlement, the rates filed in
the February 28, 2003 filing will go into effect on October 1, 2003, subject to
refund. On May 15, 2003, the FERC issued an order accepting the February 18,
2003 compliance filing.
We do not own transmission assets; however, we pay AmerenUE and AmerenCIPS
for the use of their transmission lines to transmit power. Until the tariffs and
other material terms of AmerenCIPS' and AmerenUE's participation in GridAmerica,
and GridAmerica's participation in the Midwest ISO, are finalized and approved
by the FERC, we are unable to predict the impact that on-going regional
transmission organization developments will have on our financial position,
results of operations or liquidity. AmerenUE's participation in GridAmerica is
subject to MoPSC approval. Ameren expects GridAmerica to become operational in
late 2003, subject to regulatory approvals.
In July 2003, the FERC issued an Order (July Order) that could potentially
reduce Ameren's, as well as other utilities', "through and out" transmission
revenues effective November 1, 2003, reversing an Administrative Law Judge's
previous decision on this matter. The revenues subject to elimination by the
July Order are those revenues from transmission reservations that travel through
or out of Ameren's transmission system and are also used to provide electricity
to load within the Midwest ISO or PJM Interconnection LLC systems. The
magnitude of the potential net revenue reduction resulting from the July Order
is still being evaluated, but could be up to $20 to $25 million annually. It is
anticipated that our and our affiliates' transmission revenues could be reduced
by the July Order for Ameren. Moreover, the FERC's Order explicitly permits
companies participating in an RTO to seek collection of the lost "through and
out" revenues through other rate mechanisms. At this time, Ameren intends to
seek rehearing of the July Order. Ameren also intends to seek recovery of any
potential lost "through and out" revenues through rate mechanisms acknowledged
by the FERC in the July Order.
Standard Market Design Notice of Proposed Rulemaking (NOPR)
On July 31, 2002, the FERC issued a Standard Market Design 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
9
service for all users of the transmission system including bundled retail load,
and proposes a new energy market and congestion management system that uses
locational marginal pricing as its basis.
Although issuance of the final rule is uncertain and its implementation
schedule is unknown, the Midwest ISO is already in the process of implementing a
separate market design similar to the proposed market design in the NOPR. In
July 2003, the Midwest ISO filed with the FERC a revised OATT codifying the
terms and conditions under which it will implement the new market design. The
Midwest ISO has targeted March 2004 as the start date for implementation. We are
reviewing the Midwest ISO's market design and the potential impact of the market
design on the cost and reliability of service to retail customers. At this time,
we are unable to predict the ultimate impact the new market design will have 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, our
ultimate 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
We have a power supply agreement with Marketing Company, which we refer to
as the Generating Company - Marketing Company agreement. Marketing Company, in
turn, has a power supply agreement with AmerenCIPS, which we refer to as the
Marketing Company - AmerenCIPS agreement. Under these power supply agreements,
we agree to supply to Marketing Company, and Marketing Company, in turn, agrees
to supply to AmerenCIPS, all of the energy and capacity needed by AmerenCIPS to
fulfill its obligations to offer service to its retail customers and to fulfill
AmerenCIPS' other obligations under all applicable federal and state tariffs or
contracts. For capacity and energy needed to meet its obligations to retail
tariff customers, AmerenCIPS pays Marketing Company fixed prices. For its
fixed-price retail contracts, AmerenCIPS pays Marketing Company the price it
receives under these contracts. Under the Generating Company - Marketing Company
agreement, Marketing Company "passes through" to us the amounts received under
the Marketing Company - AmerenCIPS agreement. The Marketing Company - AmerenCIPS
agreement will terminate December 31, 2004. The Generating Company - Marketing
Company agreement will remain in effect unless terminated by either party upon
at least one year's notice, but may not be terminated prior to December 31,
2004. We expect Marketing Company to seek to extend the Marketing Company -
AmerenCIPS agreement through December 31, 2006. An extension of the Marketing
Company - AmerenCIPS agreement will depend on compliance with regulatory
requirements in effect as to Marketing Company at the time, and we cannot
predict whether Marketing Company will be successful in securing an extension of
this agreement. The ICC authorized the extension of this agreement in its order
approving Ameren's acquisition of CILCORP. Electric revenues included in
Operating Revenues - Electric - Intercompany derived under the Generating
Company - Marketing Company agreement were $143 million for the three months
ended June 30, 2003 (2002 - $148 million) and were $300 million for the six
months ended June 30, 2003 (2002 - $296 million). No other customer represents
greater than 10% of our revenues. Included in electric revenues derived under
the Generating Company - Marketing Company agreement were sales to AmerenCILCO
of $2 million for the three months ended June 30, 2003 (2002 - $2 million) and
$3 million for the six months ended June 30, 2003 (2002 - $3 million).
Electric revenues included in Operating Revenues - Electric - Intercompany
derived through sales of available generation to our affiliate EEI were $1
million for the three months ended June 30, 2003 (2002 - $1 million) and were $1
million for the six months ended June 30, 2003 (2002 - $1 million).
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 Company 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 included in Operating Revenues - Electric derived from
outside sales of available generation through AmerenEnergy were $19 million for
the three months ended June 30, 2003 (2002 - $15 million) and were
10
$54 million for the six months ended June 30, 2003 (2002 - $32 million).
Electric revenues included in Operating Revenues - Electric - Intercompany
derived through sales of available generation to AmerenUE through the amended
joint dispatch agreement were $7 million for the three months ended June 30,
2003 (2002 - $8 million) and were $18 million for the six months ended June 30,
2003 (2002 - $18 million).
Purchased power derived from AmerenEnergy was $6 million for the three
months ended June 30, 2003 (2002 - $9 million) and was $15 million for the six
months ended June 30, 2003 (2002 - $17 million). Intercompany power purchases
from the amended joint dispatch agreement between AmerenUE and us and other
agreements for the three months ended June 30, 2003 were $24 million (2002 - $15
million) and were $56 million for the six months ended June 30, 2003 (2002 - $35
million).
Ameren Services and AmerenEnergy Charges
Costs of 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 June
30, 2003 were $7 million (2002 - $9 million) and were $14 million for the six
months ended June 30, 2003 (2002 - $18 million).
Non-Regulated Subsidiary Money Pool
We have the ability to borrow up to $600 million from Ameren through a
non-regulated subsidiary 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-regulated subsidiary money pool or
external sources are used by Ameren to increase the available amounts. At June
30, 2003, $595 million was available through the non-regulated subsidiary money
pool not including additional funds available through uncommitted bank lines.
The non-regulated subsidiary 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-regulated subsidiary money pool. The average
interest rate for borrowings from the non-regulated subsidiary money pool was
8.84% for the three months ended June 30, 2003 (2002 - 8.34%) and 8.84% for the
six months ended June 30, 2003 (2002 - 6.33%). These rates are based on the cost
of Ameren's funds used to fund money pool advances. We incurred $4 million in
intercompany interest expense associated with outstanding borrowings from the
non-regulated subsidiary money pool for the three months ended June 30, 2003
(2002 - $4 million net of interest income) and $9 million for the six months
ended June 30, 2003 (2002 - $5 million net of interest income). At June 30,
2003, we had borrowings of $154 million from the non-regulated subsidiary money
pool (2002 - $32 million of loans to the non-regulated subsidiary money pool).
In July 2003, Ameren entered into two new credit agreements for $470
million in revolving credit facilities to be used for general corporate
purposes, including the support of commercial paper programs. The $470 million
in new facilities includes a $235 million 364-day revolving credit facility and
a $235 million three-year revolving credit facility. These new credit facilities
replaced Ameren's existing $270 million 364-day revolving credit facility, which
matured in July 2003, and a $200 million facility, which would have matured in
December 2003. The new credit facilities contain provisions which require Ameren
to meet minimum Employee Retirement Income Security Act (ERISA) funding
requirements for Ameren's pension plan. The prior credit facilities included
more restrictive provisions related to the funded status of Ameren's pension
plan, which are not present in the new facilities. In addition, in July 2003,
Ameren entered into an amendment of an existing $130 million multi-year credit
facility that similarly modified the ERISA-related provisions in this facility.
As a result, all of Ameren's facilities require it to meet minimum ERISA funding
requirements, but do not otherwise limit the underfunded status of its pension
plan. At July 31, 2003, all of such borrowing capacity under these facilities
was available.
NOTE 4 - Derivative Financial Instruments
As of June 30, 2003, we 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 $1 million in Other Deferred Credits and
Liabilities.
11
Cash Flow Hedges
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 a gain of less than
$1 million for the three months ended June 30, 2003 (2002 - less than $1 million
loss) and was a loss of less than $1 million for the six months ended June 30,
2003 (2002 - less than $1 million gain).
As of June 30, 2003, we had hedged a portion of the electricity price
exposure for periods generally less than one year. 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 (less than $1 million, net of
taxes).
As of June 30, 2003, 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 cover 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 that began in June
2002.
Other Derivatives
We enter into option transactions to manage our positions in sulfur dioxide
allowances. Certain of these transactions are treated as non-hedge transactions
under SFAS 133. The net change in the market value of sulfur dioxide options is
recorded as Operating Revenues - Electric in the income statement. The net
change in the market value of sulfur dioxide options was a gain of less than $1
million (less than $1 million, net of taxes) for the three months ended June 30,
2003 and a gain of $1 million (less than $1 million, net of taxes) for the six
months ended June 30, 2003.
NOTE 5 - Property and Plant, Net
Property and plant, net consisted of the following at June 30, 2003 and
December 31, 2002:
================================================================================
June 30, December 31,
2003 2002
- --------------------------------------------------------------------------------
Property and plant, at original cost:
Electric $ 2,511 $ 2,462
Less accumulated depreciation and amortization 744 745
- --------------------------------------------------------------------------------
1,767 1,717
Construction work in progress: 13 50
- --------------------------------------------------------------------------------
Property and plant, net $ 1,780 $ 1,767
- --------------------------------------------------------------------------------
NOTE 6 - Debt Financings
At June 30, 2003, neither Ameren, nor any of its subsidiaries, including
us, had any off-balance sheet financing arrangements, other than operating
leases entered into in the ordinary course of business.
Amortization of debt issuance costs and any discounts for the three and six
months ended June 30, 2003 of less than $1 million (2002 - less than $1 million)
and $1 million (2002 - $1 million), respectively, were included in interest
expense in the income statement.
At June 30, 2003, Ameren and its subsidiaries, including us, were in
compliance with their financial agreement provisions and covenants.
12
ITEM 2. Managements Discussion and Analysis of Financial Condition and Results
of Operations.
OVERVIEW
AmerenEnergy Generating Company, headquartered in St. Louis, Missouri, is
an indirect wholly-owned subsidiary of Ameren Corporation (Ameren). We own and
operate a wholesale electric generation business in Illinois and Missouri. 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,
all related fuel, supply, transportation, maintenance and labor agreements,
approximately 45% of AmerenCIPS' employees, and other related rights, assets and
liabilities.
Ameren is a public utility holding company registered with the Securities
and Exchange Commission (SEC) under the Public Utility Holding Company Act of
1935 (PUHCA) and is headquartered in St. Louis, Missouri. Ameren's 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. Ameren's principal subsidiaries
and our affiliates are as follows:
o Union Electric Company, which operates a rate-regulated electric
generation, transmission and distribution business, and a rate-regulated
natural gas distribution business in Missouri and Illinois as AmerenUE.
o AmerenCIPS, which operates a rate-regulated electric and natural gas
transmission and distribution business in Illinois.
o Central Illinois Light Company, a subsidiary of CILCORP Inc. (CILCORP),
which operates a rate-regulated transmission and distribution business, an
electric generation business, and a rate-regulated natural gas distribution
business in Illinois as AmerenCILCO. Ameren completed its acquisition of
CILCORP on January 31, 2003. See Acquisitions for further information.
o AmerenEnergy Resources Company (Resources Company), which consists of non
rate-regulated operations. Subsidiaries include us, AmerenEnergy Marketing
Company (Marketing Company), which markets power for periods primarily over
one year, AmerenEnergy Fuels and Services Company (Fuels Company), which
procures fuel and manages the related risks for us and our affiliates,
AmerenEnergy Development Company (Development Company), which, as our
parent, develops and constructs generating facilities for us, and
AmerenEnergy Medina Valley Cogen (No. 4), LLC, which indirectly owns a 40
megawatt, gas-fired electric generation plant. On February 4, 2003, Ameren
completed its acquisition of AES Medina Valley Cogen (No. 4), LLC (Medina
Valley) and renamed it AmerenEnergy Medina Valley Cogen (No. 4), LLC. See
Acquisitions for further information.
o AmerenEnergy, Inc. (AmerenEnergy), which serves as a power marketing and
risk management agent for us and our affiliates for transactions of
primarily less than one year.
o Electric Energy, Inc. (EEI), which 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 Ameren and its subsidiaries, including us. Charges are based
upon the actual costs incurred by Ameren Services, as required by the
PUHCA.
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 financial statements and related notes included in our Quarterly Report
on Form 10-Q for the period ended March 31, 2003.
o Management's Discussion and Analysis of Financial Condition and Results of
Operations that appears in our Annual Report on Form 10-K for the period
ended December 31, 2002.
o The audited financial statements and related notes that appear in our
Annual Report on Form 10-K for the period ended December 31, 2002.
When we refer to our, we, us or Generating Company, 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.
We have an agreement to supply all of our power to Marketing Company
(Generating Company - Marketing Company agreement). Marketing Company then
provides all the power required for AmerenCIPS' native load requirements
(Marketing Company - AmerenCIPS agreement) and to serve its obligations under
various long-term
13
wholesale and retail contracts. Marketing Company's agreement with AmerenCIPS
expires on December 31, 2004, but Marketing Company and AmerenCIPS plan to seek
the necessary regulatory approvals to extend this agreement to December 31,
2006. If we have any power in excess of Marketing Company's needs, then
AmerenEnergy sells it on our behalf to the extent it is economical. See Note 3 -
Related Party Transactions to our Financial Statements under Item 1 of Part I of
this report for further information.
We jointly dispatch generation with our affiliate, AmerenUE. This joint
dispatch agreement requires each company to serve its load requirements from its
own least-cost generation first, but then allows access to any available excess
generation from the other company at cost. All of our sales to Marketing Company
are considered load requirements. The agreement has no expiration, but either
party may give a one year notice of termination beginning January 1, 2004.
Our results of operations and financial position are impacted by many
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 as fuel in 11 power generating units
(approximately 2,695 megawatts) for base load power and natural gas as fuel in
25 combustion turbine units (approximately 2,105 megawatts) primarily for
peaking power. The prices for these commodities can fluctuate significantly due
to the world economic and political environment, weather, production levels and
many other factors. Fluctuations in interest rates impact our cost of
borrowings, and pension and post-retirement benefits. 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.
Acquisitions
On January 31, 2003, Ameren completed its acquisition of all of the
outstanding common stock of CILCORP from The AES Corporation. CILCORP is the
parent company of Peoria, Illinois-based Central Illinois Light Company, which
operated as CILCO. With the acquisition, CILCO became an indirect Ameren
subsidiary, but remains a separate utility company, operating as AmerenCILCO. On
February 4, 2003, Ameren also completed its acquisition of AES Medina Valley
Cogen (No. 4), LLC (Medina Valley) which indirectly owns a 40 megawatt,
gas-fired electric generation plant. With the acquisition, Medina Valley, which
was renamed AmerenEnergy Medina Valley Cogen (No. 4), LLC, became a wholly-owned
subsidiary of Resources Company. The results of operations for CILCORP and
AmerenEnergy Medina Valley Cogen (No. 4), LLC were included in Ameren's
consolidated financial statements effective with the January and February 2003
acquisition dates. Our results of operations for the six months ended June 30,
2003 were not impacted by these acquisitions.
Ameren acquired CILCORP to complement its existing Illinois gas and
electric operations. The purchase included CILCO's rate-regulated electric and
natural gas businesses in Illinois serving approximately 200,000 and 205,000
customers, respectively, of which approximately 150,000 are combination electric
and gas customers. CILCO's service territory is contiguous to Ameren's service
territory. CILCO also has a non rate-regulated electric and gas marketing
business principally focused in the Chicago, Illinois region. Finally, the
purchase included approximately 1,200 megawatts of largely coal-fired generating
capacity, most of which is expected to become non rate-regulated in 2003.
The total acquisition cost was approximately $1.4 billion and included the
assumption of CILCORP and Medina Valley debt and preferred stock at closing of
$895 million and consideration of $489 million in cash, net of cash acquired.
The cash component of the purchase price came from Ameren's issuances in
September 2002 of 8.05 million common shares and its issuance in early 2003 of
an additional 6.325 million common shares which together generated aggregate net
proceeds of $575 million.
14
RESULTS OF OPERATIONS
Earnings Summary
Our net income increased $8 million to $10 million in the second quarter of
2003 from $2 million in the second quarter of 2002. Second quarter 2003 net
income increased principally as a result of lower operations and maintenance
expenses and favorable interchange margins due to improved power prices in the
energy markets. The increase in net income was partially offset by higher
interest costs associated with long-term debt issued in June 2002.
Our net income increased $34 million to $49 million for the six months
ended June 30, 2003 from $15 million during the first six months of 2002. In the
first six months of 2003, our net income included a net cumulative effect gain
of $18 million associated with the adoption of Statement of Financial Accounting
Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations." The net
gain resulted principally from the elimination of non-legal obligation costs of
removal for our assets from accumulated depreciation. In addition to the items
discussed above, net income for the first six months of 2003 benefited from
higher interchange margins as well as colder winter weather than in the first
six months of 2002, which resulted in increased native load electric demand
under the Generating Company - Marketing Company agreement in the first quarter
of 2003.
Electric Operations
The following table represents the favorable (unfavorable) variations on
electric margin for the three and six months ended June 30, 2003 from the
comparable period in 2002:
=========================================================================================================
Three Months Six Months
---------------------------------------------------------------------------------------------------------
Electric Revenues:
Interchange revenues $ 3 $ 23
Wholesale revenues (5) 4
---------------------------------------------------------------------------------------------------------
Total variation in electric operating revenues (2) 27
Fuel and Purchased Power:
Fuel:
Generation $ 10 $ 10
Price 3 4
Generation efficiencies and other 1 4
Purchased power (7) (20)
----------------------------------------------------------------------------------------------------------
Total variation in fuel and purchased power 7 (2)
----------------------------------------------------------------------------------------------------------
Change in electric margin $ 5 $ 25
----------------------------------------------------------------------------------------------------------
Electric margin increased $5 million for the three months and $25 million
for the six months ended June 30, 2003, compared to the same periods in 2002.
Increases in electric margin in the second quarter and first six months of 2003
were primarily attributable to increased interchange margins. Interchange
margins increased approximately $6 million in the second quarter and
approximately $21 million in the first six months of 2003 due to improved power
prices in the energy markets. Average power prices increased to approximately
$36 per megawatthour in the first six months of 2003 from approximately $24 per
megawatthour in the first six months of 2002.
Fuel and purchased power costs decreased approximately $7 million in the
second quarter of 2003 due to a 14% decline in megawatthour generation partially
offset by higher purchased power costs due to higher energy prices and lower
generation. Fuel and purchased power costs increased $2 million in the first six
months of 2003 due to higher purchased power costs associated with higher energy
prices and lower generation partially offset by lower generation costs due to a
21% decline in megawatthour generation. The decline in generation was primarily
attributable to the timing of outages at our power plants during the first six
months of 2003.
During 2002, we adopted the provisions of Emerging Issues Task Force (EITF)
Issue 02-3, "Issues Involved in Accounting for Derivative Contracts Held for
Trading Purposes and Contracts Involved in Energy Trading and Risk Management
Activities," that required revenues and costs associated with certain energy
contracts to be shown on a net basis in the income statement. The operating
revenues and costs that were netted for the three and six months ended June 30,
2002 were $44 million and $131 million, respectively, which reduced interchange
revenues and purchased power by equal amounts. See Note 1 - Summary of
Significant Accounting Policies to our Financial Statements under Item 1 of Part
I of this report for further information.
15
Other Operating Expenses
Other Operations and Maintenance
Other operations and maintenance expenses decreased $12 million in the
second quarter and $14 million in the first six months of 2003 compared to the
same periods in 2002, primarily due to a decrease in injuries and damages
charges, a reduction in efficiency improvement costs at our coal-fired
generation stations, a decrease in commitment fees that AmerenEnergy pays on our
behalf for the use of AmerenUE and AmerenCIPS' transmission lines, and lower
labor costs related to the voluntary employee retirement program instituted at
the end of 2002. These decreases were partially offset by higher employee
benefit costs related to higher healthcare and pension costs.
Costs of support services provided by Ameren Services and AmerenEnergy to
us, including wages, employee benefits and professional services are based on
actual costs incurred and were included in other operations and maintenance
expenses. See Note 3 - Related Party Transactions to our Financial Statements
under Item 1 of Part I of this report for further information.
Depreciation and Amortization
Depreciation and amortization expense increased $2 million in the second
quarter and $4 million in the first six months of 2003, compared to the same
periods in 2002 primarily due to our addition of four combustion turbine
generating units in the third and fourth quarters of 2002.
Other Taxes
Other taxes expense remained unchanged in the second quarter and increased
$1 million in the first six months of 2003 compared to the same periods in 2002,
primarily due to increased property taxes associated with the four combustion
turbine generating units added in the third and fourth quarters of 2002.
Interest
Interest expense increased $3 million in the second quarter and $11 million
in the first six months of 2003, compared to the same periods in 2002, primarily
due to our issuance of $275 million of 7.95% Senior Notes in June 2002 and
increased borrowings from Ameren's non-regulated subsidiary money pool at higher
interest rates in the first quarter of 2003, compared to the first quarter of
2002. These increases were partially offset by a reduction in the principal
amounts outstanding on our subordinated intercompany promissory notes to
AmerenCIPS and Ameren in May 2003 of approximately $46 million and $4 million,
respectively, therefore reducing associated interest costs in the current year
periods compared to the prior year periods.
Income Taxes
Income tax expense increased $4 million in the second quarter of 2003,
compared to the second quarter of 2002, primarily due to higher pre-tax income.
Income tax expense increased $9 million in the first six months of 2003, as
compared to the same period in 2002, primarily due to higher pre-tax income.
LIQUIDITY AND CAPITAL RESOURCES
Operating
Our cash flows provided by operating activities totaled $126 million for
the first six months of 2003, compared to $68 million for the same period in
2002. Cash provided from operating activities increased in the first six months
of 2003, primarily as a result of higher electric margins and variations in
working capital.
Investing
Our cash flows used in investing activities totaled $31 million for the
first six months of 2003 compared to $223 million for the same period in 2002.
The decrease from the prior year period was entirely related to a decrease in
construction expenditures as we paid approximately $140 million in the first
quarter of 2002 to Development Company for a combustion turbine generating unit
purchased, but not yet paid for, at December 31, 2001. Our capital expenditures
are expected to approximate $50 million in 2003.
16
We continually review our generation portfolio and expected electrical
needs, and as a result, we could modify our plan for generation capacity, which
could include the timing of when certain assets will be added to, or removed
from our portfolio, the type of generation asset technology that will be
employed, or whether capacity may be purchased, among other things. Any changes
that we plan to make for future generating needs could result in significant
capital expenditures or losses being incurred, which could be material.
Financing
Our cash flows used in financing activities totaled $90 million in the
first six months of 2003 compared to cash flows provided by financing activities
of $161 million in the first six months of 2002. Our principal financing
activities for the first six months of 2003 included partial repayments of our
intercompany promissory notes to Ameren and AmerenCIPS and redemptions of
short-term borrowings from Ameren's non-regulated subsidiary money pool. The
first six months of 2002 included issuance of $275 million of Senior Notes in
June 2002.
Notes Payable -Intercompany and Liquidity
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 $600 million from
Ameren through a non-regulated subsidiary 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-regulated subsidiary
money pool or external sources are used by Ameren to increase the available
amounts. At June 30, 2003, $595 million was available through the non-regulated
subsidiary money pool not including additional funds available through
uncommitted bank lines. The non-regulated subsidiary 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-regulated subsidiary money pool. The
average interest rate for borrowings from the non-regulated subsidiary money
pool was 8.84% for the three months ended June 30, 2003 (2002 - 8.34%) and 8.84%
for the six months ended June 30, 2003 (2002 - 6.33%). These rates are based on
the cost of Ameren's funds used to fund money pool advances. We incurred $4
million in intercompany interest expense associated with outstanding borrowings
from the non-regulated subsidiary money pool for the three months ended June 30,
2003 (2002 - $4 million net of interest income) and $9 million for the six
months ended June 30, 2003 (2002 - $5 million net of interest income). At June
30, 2003, we had borrowings of $154 million from the non-regulated subsidiary
money pool (2002 - $32 million of loans to the non-regulated subsidiary money
pool).
We and Ameren rely on access to short-term and long-term capital markets as
a significant source of funding for capital requirements not satisfied by our
operating cash flows. Our inability to raise capital on favorable terms,
particularly during times of uncertainty in the capital markets, could
negatively impact our ability to maintain and grow our businesses. Based on our
current credit ratings and those of Ameren, we believe that we will continue to
have access to the capital markets. However, events beyond our control may
create uncertainty in the capital markets such that our cost of capital would
increase or our ability to access the capital markets would be adversely
affected.
Financial Agreement Provisions and Covenants
Our financial agreements and those of Ameren include customary default or
cross default provisions that could impact the continued availability of credit
or result in the acceleration of repayment. The majority of the committed credit
facilities of Ameren and its subsidiaries require the borrower to represent, in
connection with any borrowing under the facility that no material adverse change
has occurred since certain dates. None of our financing arrangements nor those
of Ameren and its other subsidiaries contain credit rating triggers, except for
three funded bank term loans at AmerenCILCO totaling $105 million at June 30,
2003.
At June 30, 2003, Ameren and its subsidiaries, including us, were in
compliance with their financial agreement provisions and covenants.
Off-Balance Sheet Arrangements
At June 30, 2003, neither Ameren, nor any of its subsidiaries, including
us, had any off-balance sheet financing arrangements, other than operating
leases entered into in the ordinary course of business.
17
OUTLOOK
We believe there will be challenges to earnings in 2003 and beyond due to
industry-wide trends and company-specific issues. The following are expected to
put pressure on earnings in 2003 and beyond:
o Weak economic conditions, which impacts native load demand;
o Power prices in the Midwest will impact the amount of revenues we can
generate by marketing any excess power into the interchange markets.
Long-term power prices continue to be generally soft in the Midwest,
despite the fact that short-term power prices have strengthened
significantly from the prior year in the first six months of 2003 due
primarily to higher prices for natural gas;
o Fixed electric rates in our Illinois service territory;
o The adverse effects of rising employee benefit costs and higher insurance
costs; and
o An assumed return to more normal weather patterns relative to 2002.
In late 2002, we and Ameren announced the following actions to mitigate the
effect of these challenges:
o A voluntary retirement program that was accepted by approximately 550
Ameren employees, including approximately 35 of our employees and
additional employees providing support functions to us through Ameren
Services;
o Modifications to retiree employee benefit plans to increase co-payments and
limit our overall cost;
o A wage freeze in 2003 for all management employees;
o Reductions of 2003 expected capital expenditures.
We are considering additional actions, including modifications to active
employee benefits, further staffing reductions and other initiatives.
International Union of Operating Engineers (IUOE) and the International
Brotherhood of Electrical Workers (IBEW) for two bargaining units covering
approximately 71% of our entire workforce expired on July 1, 2003. The principal
issues being negotiated with regard to continuation of these labor agreements
are wages, work rules and our proposal to change the employee medical benefits
program to require employees to pay for a greater portion of their benefit
coverage. Changes to the employee medical benefits program have been agreed to
with a joint bargaining committee representing all unions; however, the changes
cannot be implemented without ratification by a majority of the collective
membership of all bargaining units. Tentative Agreement has been reached with
one of the bargaining units, which includes a new four year agreement which will
expire in 2006. Ratification of the Tentative Agreement is expected in the third
quarter of 2003. We are unable to predict whether the remaining bargaining unit
agreement will be ratified or the response of other union-represented employees
to any action by its employees. We are unable to determine what, if any, impact
these labor matters could have on our future financial condition, results of
operations or liquidity.
At December 31, 2002, Ameren recorded a minimum pension liability of $102
million, after taxes, which resulted in a charge to Accumulated Other
Comprehensive Income (Loss) (OCI) and a reduction in stockholders' equity. Our
share of the minimum pension liability was approximately $6 million, after
taxes. Based on changes in interest rates, Ameren may need to change its
actuarial assumptions for its pension plan at December 31, 2003, which could
result in a requirement to record an additional minimum pension liability.
In the ordinary course of business, we and Ameren evaluate strategies to
enhance our financial position, results of operations and liquidity. These
strategies may include potential acquisitions, divestitures, and opportunities
to reduce costs or increase revenues, and other strategic initiatives in order
to increase Ameren's 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.
REGULATORY MATTERS
See Note 2 - Rate and Regulatory Matters to our Financial Statements under
Item 1 of Part I of this report for information.
18
ACCOUNTING MATTERS
See Note 1 - Summary of Significant Accounting Policies to our Financial
Statements under Item 1 of Part I of this report.
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. We handle 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 risks and are not represented in the
following discussion.
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 both long-term and short-term variable-rate debt 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 June 30, 2003, we had $154 million of
variable rate non-regulated subsidiary money pool borrowings outstanding.
Utilizing our variable rate debt outstanding at June 30, 2003, if interest
rates increased by 1%, our annual interest expense would increase by
approximately $2 million and net income would decrease by approximately $1
million. The model does not consider the effects of the reduced level of
potential overall economic activity that would exist in such an environment. In
the event of a significant change in interest rates, management would likely
take actions to further mitigate our exposure to this market risk. However, due
to the uncertainty of the specific actions that would be taken and their
possible effects, the sensitivity analysis assumes no change in our financial
structure.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties
fail to perform as contracted. New York Mercantile Exchange (NYMEX) traded
futures contracts are supported by the financial and credit quality of the
clearing members of the NYMEX and have nominal credit risk. On all other
transactions, we are exposed to credit risk in the event of nonperformance by
the counterparties in the transaction.
Our physical and financial instruments are subject to credit risk
consisting of accounts receivable and executory contracts with market risk
exposures. Our revenues are primarily derived from the sales of electricity to
Marketing Company as described in Note 3 - Related Party Transactions to our
Financial Statements under Item 1 of Part I of this report. At June 30, 2003,
approximately $51 million of our accounts receivable are related party
receivables from Marketing Company. No other customer represents greater than
10% of our accounts receivable. We analyze each counterparty's financial
condition prior to entering into sales, forwards, swaps, futures or option
contracts. We also establish credit limits for these counterparties and monitor
the appropriateness of these limits on an ongoing basis through a credit risk
management program which involves daily exposure reporting to senior management,
master trading and netting agreements, and credit support management such as
letters of credit and parental guarantees.
Equity Price Risk
Generating Company, along with other subsidiaries of Ameren, is 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
19
equity market since 2000 for the pension and postretirement plans. As a result,
at December 31, 2002, Ameren and its subsidiaries, including us, recognized an
additional minimum pension liability as prescribed by SFAS No. 87, "Employers'
Accounting for Pensions." The liability resulted in a reduction to equity as a
result of a charge to Ameren's OCI of $102 million, net of taxes. Our portion of
this charge to OCI was $6 million, net of taxes. The amount of the liability was
the result of asset returns experienced through 2002, interest rates and
Ameren's contributions to the plan during 2002. Neither Ameren's nor our portion
of the minimum pension liability changed at June 30, 2003. In future years, the
liability recorded, the costs reflected in net income or OCI, or cash
contributions to the plans could increase materially without a recovery in
equity markets in excess of our assumed return on plan assets. 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 equity would be restored in the Balance Sheet.
Fair Value of Contracts
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 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 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 under Item 1 of Part I of this report for further
information.
The following table summarizes the favorable (unfavorable) changes in the
fair value of all contracts marked-to-market during the three and six months
ended June 30, 2003:
===================================================================================================================
Three Six
Months Months
- -------------------------------------------------------------------------------------------------------------------
Fair value of contracts at beginning of period, net $ - $ (a)
Contracts which were realized or otherwise settled during the period (a) (a)
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) 1
- -------------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at end of period, net $ (a) $ 1
===================================================================================================================
(a) Less than $1 million.
Maturities of contracts as of June 30, 2003 were as follows:
===========================================================================================================
Maturity Maturity in
less than Maturity Maturity excess of 5 Total fair
Sources of fair value 1 year 1-3 years 4-5 years 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) - - 1
- -----------------------------------------------------------------------------------------------------------
Total $ (d) $ (d) $ - $ - $ 1
===========================================================================================================
(a) All contracts were with investment-grade rated counterparties.
(b) Principally power forward values based on NYMEX prices for over-the-counter contracts.
(c) Principally sulfur dioxide options valued on information from external sources and our
estimates.
(d) Less than $1 million.
20
ITEM 4. Controls and Procedures.
(a) Evaluation of Disclosure Controls and Procedures
As of June 30, 2003, the principal executive officer and principal
financial officer of AmerenEnergy Generating Company have evaluated the
effectiveness of the design and operation of AmerenEnergy Generating Company's
disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15
(e) of the Securities Exchange Act of 1934, as amended (Exchange Act)). Based
upon that evaluation, the principal executive officer and principal financial
officer of AmerenEnergy Generating Company have concluded that such disclosure
controls and procedures are effective in timely alerting them to any material
information relating to AmerenEnergy Generating Company which is required to be
included in AmerenEnergy Generating Company's reports filed or submitted with
the SEC under the Exchange Act.
(b) Change in Internal Controls Over Financial Reporting
There has been no significant change in AmerenEnergy Generating Company's
internal control over financial reporting that occurred during AmerenEnergy
Generating Company's most recent fiscal quarter that has materially affected, or
is reasonably likely to materially affect, Ameren Energy Generating Company's
internal control over financial reporting.
FORWARD-LOOKING STATEMENTS
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 subsequent
securities filings and others, could cause results to differ materially from
management expectations as suggested by such "forward-looking" statements:
o the effects of 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 Federal Energy Regulatory
Commission-approved Regional Transmission Organization, including
activities associated with the Midwest Independent System Operator;
o availability and future market prices for fuel for the production of
electricity, such as coal and natural gas, purchased power, electricity for
distribution, including the use of financial and derivative instruments,
the volatility of changes in market prices and the ability to recover
increased costs;
o wholesale and retail prices for electricity in the Midwest;
o business and economic conditions;
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 benefit costs, including changes in returns of
benefit plan assets;
o disruptions of the capital markets or other events making our or Ameren's
access to necessary capital more difficult or costly;
o competition from other generating facilities, including new facilities that
may be developed in the future;
21
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;
o legal and administrative proceedings; and
o delays in or difficulties in connection with the receipt of regulatory
approvals with respect to AmerenUE's plan to discontinue operating as a
public utility subject to ICC regulation and the transferring of AmerenUE's
Illinois-based electric and natural gas businesses to AmerenCIPS or
unexpected adverse conditions or terms of those approvals..
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.
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PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings.
On June 18, 2003, twenty retirees and surviving spouses of retirees of our
parent, Ameren Corporation, or its predecessors or subsidiaries (the plaintiffs)
filed a complaint in the U.S. District Court, Southern District of Illinois,
against Ameren, and its subsidiaries, Union Electric Company, operating as
AmerenUE, Central Illinois Public Service Company, operating as AmerenCIPS,
Ameren Energy Resources Company, Ameren Services Company and us, and against
Ameren's Retiree Medical Plan (the defendants). The retirees were members of
various local labor unions of the International Brotherhood of Electrical
Workers (IBEW) and the International Union of Operating Engineers (IUOE). The
complaint alleges the following:
o the labor organizations which represented the plaintiffs have historically
negotiated retiree medical benefits with the defendants and that pursuant
to the negotiated collective bargaining agreements and other negotiated
documents, the plaintiffs are guaranteed medical benefits at no cost or at
a fixed maximum cost during their retirement;
o Ameren has unilaterally announced that, beginning in 2004, retirees must
pay a portion of their own health care premiums and either an increasing
portion of their dependents' premiums or newly imposed dependents'
premiums, and that surviving spouses will be paying increased amounts for
their medical benefits;
o the defendants' actions deprive the plaintiffs of vested benefits and thus
violate the Employee Retirement Income Security Act and the Labor
Management Relations Act of 1947, and constitute a breach of the
defendants' fiduciary duties; and
o the defendants are estopped from changing the plan benefits.
The plaintiffs have filed the complaint on behalf of themselves, other
similarly situated former non-management employees and their surviving spouses
who retired from January 1, 1992 through October 1, 2002, and on behalf of all
subsequent non-management retirees and their surviving spouses whose vested
medical benefits are reduced or are threatened with reduction. The plaintiffs
seek to have this lawsuit certified as a class action, injunctive relief and
declaratory relief, actual damages for any amounts they are made to pay as a
result of the defendants' actions, and payment of attorney fees and costs. On
August 11, 2003, the defendants filed motions to dismiss various counts of the
complaint. We are unable to predict the outcome of this lawsuit or the impact of
the outcome on our financial position, results of operations or liquidity.
On July 8, 2003, we and our direct parent, Ameren Energy Development
Company, as well as U.S. Can Company, filed a complaint in the Circuit Court of
Cook County, Illinois, Chancery Division, against the Village of Bartlett,
Illinois, the Village Trustees, and Realen Homes, LP, a Pennsylvania limited
partnership, seeking a declaratory judgment and/or writ of certiorari to
invalidate decisions by the Village of Bartlett on June 3, 2003 to annex and
rezone properties for a proposed project to be developed by Realen Homes. The
project would consist of approximately 210 single family and 119 town house
units on land located across from our combustion turbine generating units, U.S.
Can Company's plant and other industrial facilities in Elgin, Illinois. The
proposed residential project could impact, among other things, our ability to
meet certain state and local noise standards.
Reference is made to Note 2 to the Notes to Financial Statements in our
Form 10-Q for the quarterly period ended March 31, 2003 for a discussion of the
Missouri Supreme Court's opinion issued in April 2003 upholding the adoption of
affiliate rules by the Missouri Public Service Commission for Missouri's gas and
electric utilities. AmerenUE had originally appealed the adoption of the
asymmetric pricing provisions contained in the affiliate rules. In May 2003, the
Missouri Supreme Court denied AmerenUE's Motion for Reconsideration of the
court's April 2003 opinion which makes the affiliate rules applicable to
AmerenUE and its affiliates, including us. We do not expect these rules to have
a material adverse impact on our future financial position, cash flows or
results of operations.
Note 2 - Rate and Regulatory Matters to our Financial Statements under Item
1 of Part I of this report contains additional information on legal and
administrative proceedings which is incorporated by reference under this item.
23
ITEM 5. Other Information.
Reference is made to Item 2. "Properties" in Part I of our 2002 Annual
Report on Form 10-K for a discussion of the location of our generating
facilities within MAIN (Mid-America Interconnected Network), which is one of the
regional electric reliability councils organized for coordinating the planning
and operation of the nation's bulk power supply. On June 23, 2003, our
affiliates, AmerenUE, AmerenCIPS and Central Illinois Light Company, operating
as AmerenCILCO, provided formal written notice to the MAIN Board of Directors of
their intent to withdraw from MAIN effective January 1, 2005. They intend to
join another Regional Reliability Organization (RRO) prior to their withdrawal
from MAIN becoming effective. Until their withdrawal is effective, they will
continue to honor all of their obligations as members of MAIN. If they do not
join another RRO, they may withdraw their notice of intent to withdraw from
MAIN.
ITEM 6. Exhibits and Reports on Form 8-K.
(a) Exhibits filed herewith.
31.1 - Rule 13a -14(a)/15d-14(a) Certification of Principal
Executive Officer (required by Section 302 of
the Sarbanes-Oxley Act of 2002).
31.2 - Rule 13a-14(a)/15d-14(a) Certification of Principal
Financial Officer (required by Section 302 of the
Sarbanes-Oxley Act of 2002).
32.1 - Section 1350 Certification of Principal Executive Officer
(required by Section 906 of the Sarbanes-Oxley Act of
2002).
32.2 - Section 1350 Certification of Principal Financial Officer
(required by Section 906 of the Sarbanes-Oxley Act of
2002).
(b) Reports on Form 8-K. Ameren Energy Generating Company filed the
following reports on Form 8-K during the quarterly period ended
June 30, 2003:
======================================================================
Items Financial
Date of Report Reported Statements Filed
----------------------------------------------------------------------
May 30, 2003 5 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 Union Electric Company on Forms 8-K, 10-Q and 10-K
are on file with the SEC under File Number 1-2967.
Reports of Central Illinois Public Service Company on Forms
8-K, 10-Q and 10-K are on file with the SEC under File
Number 1-3672.
Reports of CILCORP Inc. on Forms 8-K, 10-Q and 10-K are on file
with the SEC under File Number 2-95569.
Reports of Central Illinois Light Company on Forms 8-K, 10-Q
and 10-K are on file with the SEC under File Number 1-2732.
24
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
Vice President and Controller
(Principal Accounting Officer)
Date: August 14, 2003
25