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 March 31, 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 May 14, 2003:
Common Stock, no par value, held by AmerenEnergy Development Company (parent
company of the registrant) - 2,000.
AMEREN ENERGY GENERATING COMPANY
TABLE OF CONTENTS
Page
PART I. Financial Information
ITEM 1. Financial Statements (Unaudited)
Balance Sheet at March 31, 2003 and December 31, 2002........................................ 1
Statement of Income for the three months ended March 31, 2003 and 2002....................... 2
Statement of Cash Flows for the three months ended March 31, 2003 and 2002................... 3
Statement of Common Stockholder's Equity for the three months ended
March 31, 2003 and 2002...................................................................... 4
Notes to Financial Statements................................................................ 5
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........ 12
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk................................... 20
ITEM 4. Controls and Procedures...................................................................... 22
PART II. Other Information
ITEM 1. Legal Proceedings............................................................................ 24
ITEM 6. Exhibits and Reports on Form 8-K............................................................. 24
SIGNATURE................................................................................................. 25
CERTIFICATIONS............................................................................................ 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, Item 2. "Management's
Discussion and Analysis of Financial Condition and Results of Operations,"
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)
March 31, December 31,
2003 2002
----------------- ---------------
ASSETS:
Property and plant, net $ 1,790 $ 1,767
Current assets:
Cash and cash equivalents 3 3
Accounts receivable 12 10
Accounts receivable - intercompany 81 68
Other receivables 5 2
Materials and supplies, at average cost -
Fossil fuel 53 50
Other 23 27
Taxes receivable 61 71
Other 2 -
----------------- ---------------
Total current assets 240 231
Other 14 12
----------------- ---------------
Total Assets $ 2,044 $ 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 169 131
Accumulated other comprehensive income (1) (1)
----------------- ---------------
Total common stockholder's equity 318 280
----------------- ---------------
Subordinated notes payable - intercompany 412 412
Long-term debt 698 698
----------------- ---------------
Total capitalization 1,428 1,390
----------------- ---------------
Current liabilities:
Current portion of subordinated notes payable - intercompany 50 50
Accounts and wages payable 36 55
Accounts and wages payable - intercompany 29 32
Asset retirement obligation 4 -
Notes payable - intercompany 170 191
Current portion of income taxes payable - intercompany 13 13
Interest payable 21 8
Interest payable - intercompany 8 7
Other 3 2
----------------- ---------------
Total current liabilities 334 358
----------------- ---------------
Deferred income taxes, net 86 66
Accumulated deferred investment tax credits 15 15
Income tax payable - intercompany 159 162
Other deferred credits and liabilities 22 19
----------------- ---------------
Total Capital and Liabilities $ 2,044 $ 2,010
================= ===============
See Notes to Financial Statements.
1
AMEREN ENERGY GENERATING COMPANY
STATEMENT OF INCOME
(Unaudited, in millions)
Three Months Ended
March 31,
----------------------------
2003 2002
------------- ------------
OPERATING REVENUES:
Electric - intercompany $ 168 $ 157
Electric 35 16
Other - intercompany 3 3
------------- ------------
Total operating revenues 206 176
------------- ------------
OPERATING EXPENSES:
Fuel and purchased power 88 79
Other operations and maintenance 35 37
Depreciation and amortization 18 16
Other taxes 7 6
------------- ------------
Total operating expenses 148 138
------------- ------------
OPERATING INCOME 58 38
OTHER INCOME AND (DEDUCTIONS):
Miscellaneous, net -
Miscellaneous income 2 -
------------- ------------
Total other income and (deductions) 2 -
------------- ------------
INTEREST CHARGES:
Interest expense - intercompany 12 9
Interest expense 14 8
------------- ------------
Total interest charges 26 17
------------- ------------
INCOME TAXES 13 8
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE 21 13
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES 18 -
------------- ------------
NET INCOME $ 39 $ 13
============= ============
See Notes to Financial Statements.
2
AMEREN ENERGY GENERATING COMPANY
STATEMENT OF CASH FLOWS
(Unaudited, in millions)
Three Months Ended
March 31,
---------------------
2003 2002
--------- ---------
Cash Flows From Operating:
Net income $ 39 $ 13
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting principle (18) -
Depreciation and amortization 18 16
Deferred income taxes, net 20 5
Other - (2)
Changes in assets and liabilities:
Accounts receivable (2) (5)
Accounts receivable - intercompany (16) 58
Materials and supplies 1 2
Taxes receivable, net (2) 7
Accounts and wages payable (19) (32)
Accounts and wages payable - intercompany (3) (23)
Current portion of income taxes payable-intercompany (3) (7)
Interest payable 13 8
Interest payable - intercompany 1 2
Assets, other (1) 1
Liabilities, other 4 6
--------- ---------
Net cash provided by operating activities 32 49
--------- ---------
Cash Flows Used In Investing:
Construction expenditures (10) (154)
--------- ---------
Net cash used in investing activities (10) (154)
--------- ---------
Cash Flows From Financing:
Dividends paid to Ameren (1) (1)
Redemptions:
Notes payable - intercompany (21) -
Issuances:
Notes payable - intercompany - 109
--------- ---------
Net cash (used in) provided by financing activities (22) 108
--------- ---------
Net change in cash and cash equivalents - 3
Cash and cash equivalents at beginning of year 3 2
--------- ---------
Cash and cash equivalents at end of period $ 3 $ 5
========= =========
Cash paid during the periods:
Interest - intercompany $ 11 $ 7
Income taxes - 1
See Notes to Financial Statements.
3
AMEREN ENERGY GENERATING COMPANY
STATEMENT OF COMMON STOCKHOLDER'S EQUITY
(Unaudited, in millions)
Three Months Ended
March 31,
--------------------------
2003 2002
------------ ------------
Common stock $ - $ -
Other paid-in capital
Beginning balance 150 150
Change in current period - -
------------ ------------
150 150
------------ ------------
Retained earnings
Beginning balance 131 120
Net income 39 13
Dividends paid to Ameren (1) (1)
------------ ------------
169 132
------------ ------------
Accumulated other comprehensive income
Beginning balance 5 4
Change in derivative financial instruments in current period - (2)
------------ ------------
5 2
------------ ------------
Beginning balance - minimum pension liability (6) -
Change in minimum pension liability in current period - -
------------ ------------
(1) 2
------------ ------------
Total common stockholder's equity $ 318 $ 284
============ ============
Comprehensive income, net of taxes
Net income $ 39 $ 13
Unrealized net gain/(loss) on derivative hedging instruments,
net of income taxes of $-, and $(1), respectively - (1)
Reclassification adjustments for gains/(losses) included in net income
net of income taxes of $-, and $(1), respectively - (1)
------------ ------------
Total comprehensive income, net of taxes $ 39 $ 11
============ ============
See Notes to Financial Statements.
4
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
March 31, 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,
which we refer to as the coal plants, all related fuel, supply, transportation,
maintenance and labor agreements, approximately 45% of AmerenCIPS' employees,
and other related rights, assets and liabilities.
Ameren is a public utility holding company registered with the Securities
and Exchange Commission 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 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) from AES 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
5
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the reported
period. Actual results could differ from those estimates. 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 on 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, and the corresponding increases in
asset book values are depreciated over the useful life of the related asset.
Uncertainties as to the probability, timing or cash flows associated with an
asset retirement obligation affect our estimate of fair value.
Upon adoption of this standard on January 1, 2003, we recognized 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
property plant as well as the majority of net after-tax gain we recognized upon
adoption of $18 million 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 requires 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 notional amount of the power sales contracts with
a corresponding charge to income for the costs of the energy that was generated,
or for the notional amount of a purchased power contract.
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
6
Hedging Activities") trading derivatives (subsequent to the rescission of EITF
98-10) should be shown net in the 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. We
have adopted and applied this guidance to 2002 and 2001, which had no impact on
previously reported earnings or stockholder's equity. The operating revenues and
costs netted for the three months ended March 31, 2002 were $87 million, which
reduced interchange and other revenues and purchased power and other costs 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.
FASB Interpretation No. (FIN) 45 - "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others"
FIN 45 was issued in November 2002 and requires that upon issuance of
certain guarantees, a guarantor must recognize a liability for the fair value of
the obligation assumed under the guarantee. These recognition provisions of FIN
45 are to be applied on a prospective basis to guarantees issued or modified
after December 31, 2002, irrespective of the guarantor's fiscal year-end. FIN 45
also requires additional disclosures by a guarantor in its interim and annual
financial statements for periods ending after December 15, 2002. Because we do
not have such obligations, the recognition provisions of FIN 45 did not have any
effect on our financial position, results of operations or liquidity in the
first quarter of 2003.
SFAS No. 149 - "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities"
In April 2003, SFAS 149 was issued. SFAS 149 clarifies under what
circumstances a contract with initial net investment meets the characteristic 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. At this
time, we are assessing the impact of SFAS 149 on our financial position, results
of operations and liquidity upon adoption.
Revenue
Interchange revenues included in Operating Revenues - Electric were $35
million and interchange revenues included in Operating Revenues - Electric -
Intercompany were $11 million for the three months ended March 31, 2003 (2002 -
$16 million in Operating Revenues - Electric and $10 million in Operating
Revenues - Electric - Intercompany).
Purchased Power
Purchased power included in Operating Expenses - Fuel and Purchased Power
was $41 million for the three months ended March 31, 2003 (2002 - $28 million).
NOTE 2 - Rate and Regulatory Matters
Intercompany Sale of Electric Generating Facilities
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, which 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
contending that NRG's 640 megawatt generating facility at Vandalia, Missouri,
known as
7
the Audrain Facility, was a better resource for AmerenUE to acquire as compared
to our Kinmundy and Pinckneyville combustion turbine generating units.
In addition, in April 2003, in the ICC proceeding, the ICC Staff filed
testimony which expressed concerns about the sale as to whether it is the least
cost resource for AmerenUE and recommended that the ICC deny approval of the
sale. AmerenUE will have an opportunity to file testimony responding to the
recommendations of the ICC Staff and NRG.
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. AmerenUE will
have an opportunity to file testimony responding to the recommendations of the
ICC Staff and NRG. At this time, we are unable to predict the ultimate outcome
of these proceedings or the timing of the decisions of the FERC and the ICC.
Affiliate Rules
On April 22, 2003 the Missouri Supreme Court issued an opinion upholding
the adoption of affiliate rules by MoPSC for Missouri's gas and electric
utilities. AmerenUE had objected to the Missouri asymmetric pricing provisions
contained in the rules. These provisions require that the utility pay the lower
of cost or market when it is receiving services from an affiliate, and charge
the higher of cost or market when it is providing services to an affiliate. In
general, the rules are intended to prevent regulated utilities from subsidizing
their affiliates' non rate-regulated operations, such as our operations. As a
registered holding company under the PUHCA, Ameren and its affiliates are
already subject to extensive regulation designed to prevent
cross-subsidization. The asymmetric pricing provisions of the MoPSC affiliate
rules are expected to impose additional administrative burdens on AmerenUE. In
May 2003, AmerenUE filed with the Missouri Supreme Court a motion for
reconsideration of its April 22 opinion. We do not expect that the rules would
have a material adverse impact on our future financial position, results of
operations or cash flows in the event that AmerenUE's motion is denied.
Regional Transmission Organization
Since April 2002, AmerenUE and 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 judge
procedures to determine the justness and reasonableness of the proposed rate
amendments to the Midwest ISO OATT. An order in response to the February 18,
2003 filing is still pending.
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 AmerenUE and AmerenCIPS' 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.
8
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 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. On November 15, 2002, Ameren filed its
initial comments on the NOPR with the FERC expressing concern with the potential
impact of the proposed rules in their current form on the cost and reliability
of service to retail customers. Ameren also proposed that certain modifications
be made to the proposed rules in order to protect transmission owners from the
possibility of trapped transmission costs that might not be recoverable from
ratepayers as a result of inconsistent regulatory policies. Ameren filed
additional comments on the remaining sections of the NOPR during the first
quarter of 2003.
On April 28, 2003 the FERC issued a "white paper" reflecting comments
received in response to the NOPR. More specifically, the white paper indicated
that the FERC will not assert jurisdiction over the transmission rate component
of bundled retail service and will insure that existing bundled retail customers
retain their existing transmission rights and retain rights for future load
growth in its final rule. Moreover, the white paper acknowledged that the final
rule will provide the states with input on resource adequacy requirements,
allocation of firm transmission rights, and transmission planning. The FERC also
requested input on the flexibility and timing of the final rule's
implementation.
Even though issuance of the final rule and its implementation schedule are
still unknown, the Midwest ISO is already in the process of implementing a
market design similar to the proposed market design in the NOPR. The Midwest ISO
has targeted March 2004 as the start date for implementation. We are in the
process of reviewing the FERC's white paper. Until the FERC issues a final rule,
we are unable to predict the ultimate impact on our future financial position,
results of operations or liquidity.
NOTE 3 - Related Party Transactions
We have transactions in the normal course of business with Ameren, 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. 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.
Marketing Company expects to seek to renew or extend the Marketing Company -
AmerenCIPS agreement through January 1, 2007. A renewal or extension of the
Marketing Company - AmerenCIPS agreement will depend on compliance with
regulatory requirements in effect at the time, and we cannot predict whether
Marketing Company will be successful in securing a renewal or extension of this
agreement. Electric revenues derived under the Generating Company - Marketing
Company agreement were $157 million for the three months ended March 31, 2003
(2002 - $147 million). No other customer represents greater than 10% of our
revenues.
9
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 derived from outside sales of available generation
through AmerenEnergy were $35 million for the three months ended March 31, 2003
(2002 - $16 million). Electric revenues derived through sales of available
generation to AmerenUE through the amended joint dispatch agreement were $11
million for the three months ended March 31, 2003 (2002 - $10 million).
Purchased power derived from AmerenEnergy was $8 million for the three
months ended March 31, 2003 (2002 - $8 million). Intercompany power purchases
from the amended joint dispatch agreement between AmerenUE and us and other
agreements for the three months ended March 31, 2003 were $32 million (2002 -
$20 million).
Other Electric Revenues - Intercompany
Electric revenues derived through sales of available generation to our
affiliate EEI were less than $1 million for the three months ended March 31,
2003 (2002 - less than $1 million).
Ameren Services and AmerenEnergy Charges
Support services provided by our affiliates, Ameren Services and
AmerenEnergy, including wages, employee benefits, professional services and
other expenses are based on actual costs incurred. Other operating expenses
provided by Ameren Services and AmerenEnergy, for the three months ended March
31, 2003 were $7 million (2001 - $10 million).
Non-Utility Money Pool
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-utility money pool agreement. However, the total amount
available to us at any time is reduced by the amount of borrowings from Ameren
by our affiliates and is increased to the extent other Ameren non-regulated
companies advance surplus funds to the non-utility money pool or external
sources are used by Ameren to increase the available amounts. At March 31, 2003,
$600 million was available through the non-utility money pool not including
additional funds available through invested cash balances at Ameren and
uncommitted bank lines. The non-utility money pool was established to coordinate
and provide for short-term cash and working capital requirements of Ameren's
non-regulated activities and is administered by Ameren Services. Interest is
calculated at varying rates of interest depending on the composition of internal
and external funds in the non-utility money pool. The average interest rate for
borrowings from the non-utility money pool was 8.84% for the three months ended
March 31, 2003 (2002 - 4.30%). These rates are based on the cost of Ameren's
funds used to fund money pool advances. We incurred $5 million in intercompany
interest expense associated with outstanding borrowings from the non-utility
money pool for the three months ended March 31, 2003 (2002 - $1 million). At
March 31, 2003, we had borrowings of $170 million from the non-utility money
pool (2002 - borrowings of $191 million).
NOTE 4 - Derivative Financial Instruments
As of March 31, 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.
10
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
Accumulated Other Comprehensive Income (OCI) due to transactions going to
delivery or settlement, was approximately a loss of less than $1 million for the
three months ended March 31, 2003 (2002 - less than $1 million gain).
As of March 31, 2003, we had hedged a portion of the electricity price
exposure for the upcoming twelve-month period. The mark-to-market value
accumulated in OCI for the effective portion of hedges of electricity price
exposure was a gain of less than $1 million.
As of March 31, 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 covered the first ten years of debt that has a 30-year
maturity and the gain in OCI is being amortized over a ten-year period beginning
in June 2002.
Other Derivatives
We enter into option transactions to manage our positions in sulfur dioxide
allowances. Most 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 $1 million
(less than $1 million, net of taxes) for the three months ended March 31, 2003
(2002 - gain of less than $1 million).
NOTE 5 - Property and Plant, Net
Property and plant, net consisted of the following at March 31, 2003 and
December 31, 2002:
=======================================================================================================
March 31, December 31,
2003 2002
- -------------------------------------------------------------------------------------------------------
Property and plant, at original cost:
Electric $ 2,505 $ 2,462
Less accumulated depreciation and amortization 726 745
- -------------------------------------------------------------------------------------------------------
1,779 1,717
Construction work in progress: 11 50
- -------------------------------------------------------------------------------------------------------
Property and plant, net $ 1,790 $ 1,767
=======================================================================================================
NOTE 6 - Debt Financings
At March 31, 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. At this time, we do not
expect to engage in any significant off-balance sheet financing arrangements.
Amortization of debt issuance costs and any discounts for the three months
ended March 31, 2003 were less than $1 million (2002 - less than $1 million) and
were included in interest expense in the income statement.
At March 31, 2003, Ameren and its subsidiaries, including us, were in
compliance with their financial agreement provisions and covenants.
11
ITEM 2. Management's 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,
which we refer to as the coal plants, all related fuel, supply, transportation,
maintenance and labor agreements, approximately 45% of AmerenCIPS' employees,
and other related rights, assets and liabilities.
Ameren is a public utility holding company registered with the Securities
and Exchange Commission 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 Recent Developments 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
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) from AES and renamed
it AmerenEnergy Medina Valley Cogen (No. 4), LLC. See Recent
Developments 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.
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 wholesale and retail contracts. Our agreement with Marketing
Company and Marketing Company's agreement with AmerenCIPS expire on December 31,
2004, but Marketing Company and AmerenCIPS plan to seek the necessary regulatory
approvals to extend these agreements to January 1, 2007. 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
12
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, including both controllable and uncontrollable factors. Weather,
economic conditions, and the actions of key customers or competitors can
significantly impact the demand for our services. Our results are also impacted
by seasonal fluctuations caused by winter heating, and summer cooling, demand.
We principally utilize coal in 11 power generating units (approximately 2,570
megawatts) and natural gas in our 25 combustion turbine units (approximately
2,105 megawatts) that are primarily used 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. 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.
RESULTS OF OPERATIONS
Earnings Summary
Our net income increased to $39 million in the first quarter of 2003 from
$13 million in the first quarter of 2002. Net income in the first quarter of
2003 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. See Note 1 - Summary of Significant Accounting
Policies to our Financial Statements under Item 1 of Part I of this report.
Excluding the cumulative effect of change in accounting principle related
to SFAS 143, net income increased $8 million in the first quarter of 2003
compared to the prior year quarter due to an increase in electric margin ($13
million, net of taxes), generated by increased margins on interchange sales due
to 90% higher power prices in the energy markets in 2003 than in the prior year
quarter and increased sales to new and existing wholesale customers. Net income
also increased due to lower other operations and maintenance costs ($1 million,
net of taxes) associated with a reduction in commitment fees for electric
transmission line usage and a reduction in bad debt expense, partially offset by
higher employee wages and benefits and other general operations costs. These
favorable impacts to net income were partially offset by higher depreciation ($1
million, net of taxes) and other taxes expenses ($1 million, net of tax)
associated with the new combustion turbine generating units added during the
fourth quarter of 2002 and increased interest costs ($5 million, net of taxes)
associated with replacing short-term borrowings for previous capacity additions
with longer term borrowings at higher interest rates.
Recent Developments
Acquisitions
On January 31, 2003, Ameren completed its acquisition of all of the
outstanding common stock of CILCORP from The AES Corporation (AES). CILCORP is
the parent company of Peoria, Illinois-based Central Illinois Light Company,
which operated as CILCO. With the acquisition, CILCO became an 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 as 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 quarter ended
March 31, 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
13
approximately 1,200 megawatts of largely coal-fired generating capacity, most of
which is expected to become non rate-regulated in 2003.
The total purchase price 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 $488 million in cash including related
acquisition costs, net of cash acquired. The purchase price is subject to
certain adjustments for working capital and other changes pending the
finalization of CILCORP's closing balance sheet. 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.
Credit Ratings
In April 2002, as a result of AmerenUE's then pending Missouri electric
earnings complaint case and the CILCORP transaction and related assumption of
debt, credit rating agencies placed Ameren Corporation's and its subsidiaries'
debt under review. Following the completion of the acquisition of CILCORP in
January 2003, Standard & Poor's lowered the ratings of Ameren Corporation,
AmerenUE and AmerenCIPS and increased the ratings of CILCORP, AmerenCILCO and
us. At the same time, Standard & Poor's changed the outlook assigned to all of
Ameren's ratings to stable. Moody's also lowered Ameren Corporation's and
AmerenUE's ratings subsequent to the acquisition and changed the outlook on
these ratings to stable. These actions were consistent with the actions the
rating agencies disclosed they were considering following the announcement of
the CILCORP acquisition.
As of April 30, 2003, selected ratings by Moody's and Standard & Poor's
were as follows:
================================================================================
Moody's Standard & Poor's
- --------------------------------------------------------------------------------
Ameren Corporation:
Issuer/Corporate credit rating A3 A-
Unsecured debt A3 BBB+
Commercial paper P-2 A-2
AmerenUE:
Secured debt A1 A-
Unsecured debt A2 BBB+
Commercial paper P-1 A-2
CILCORP:
Unsecured debt Baa2 BBB+
AmerenCILCO:
Secured debt A2 A-
AmerenCIPS:
Secured debt A1 A-
Unsecured debt A2 BBB+
Generating Company:
Unsecured debt A3/Baa2 A-
================================================================================
Any adverse change in our, Ameren's or its other subsidiaries' credit
ratings may reduce our access to capital and/or increase the costs of borrowings
resulting in a negative impact on earnings. A credit rating is not a
recommendation to buy, sell or hold securities and should be evaluated
independently of any other rating. Ratings are subject to revision or withdrawal
at any time by the assigning rating organization.
14
Electric Operations
The following table represents the favorable (unfavorable) variation for
the three months ended March 31, 2003 from the comparable period in 2002:
================================================================================
Three Months
- --------------------------------------------------------------------------------
Electric Revenues:
Interchange revenues $ 21
Wholesale revenues 9
- --------------------------------------------------------------------------------
Total variation in electric operating revenues 30
Fuel and Purchased Power:
Fuel:
Generation $ 3
Price 1
Generation efficiencies and other -
Purchased power (13)
- --------------------------------------------------------------------------------
Total variation in fuel and purchased power (9)
================================================================================
Change in electric margin $ 21
================================================================================
Electric margin increased $21 million for the three months ended March 31,
2003 compared to the same period in 2002. Increases in electric margin in the
first quarter of 2003 were primarily due to higher power prices coupled with
increases in wholesale sales. Average power prices increased from approximately
$22 per megawatthour in the first quarter of 2002 to approximately $42 per
megawatthour in the first quarter of 2003. In addition, a net increase in new
wholesale customers added by Marketing Company and an increase in sales to
existing wholesale customers due to colder winter weather increased revenues.
These factors were partially offset by an increase in purchased power due to
higher demand and a 7% decline in megawatthours generated in the first quarter
of 2003 due to the timing of outages at our plants and the mothballing of two of
our units in December 2002.
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 netted for the three months ended March 31, 2002 were $87
million, which reduced interchange and other 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.
Other Operating Expenses
Other Operations and Maintenance
Other operations and maintenance expenses decreased $2 million in the first
quarter of 2003 compared to the first quarter of 2002, primarily due to a
decrease in costs associated with commitment fees that AmerenEnergy pays on our
behalf for the use of AmerenUE and AmerenCIPS' transmission lines ($2 million)
and a decrease in bad debt expense ($1 million). These decreases were offset by
higher employee benefit costs ($2 million) related to increasing healthcare
costs and the investment performance of employee benefit plans' assets.
Ameren Services and AmerenEnergy provided services to us, including wages,
employee benefits and professional services that 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 first
quarter of 2003 compared to the first quarter of 2002 primarily due to the
addition of the new combustion turbine generating units in the fourth quarter of
2002.
15
Other Taxes
Other taxes expense increased $1 million in the first quarter of 2003
compared to the first quarter of 2002, primarily due to increased property taxes
associated with the new combustion turbine generating units added in the fourth
quarter of 2002.
Interest
Interest expense increased $9 million in the first quarter of 2003 compared
to the first quarter of 2002, primarily due to our issuance of $275 million of
7.95% Senior Notes in June 2002 and increased borrowings from Ameren's
non-utility 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 of approximately $43
million and $4 million, respectively, therefore reducing associated interest
costs in the current year quarter compared to the prior year quarter.
Income Taxes
Income tax expense increased $5 million in the first quarter of 2003,
compared to the first quarter of 2002, primarily due to higher pretax income.
LIQUIDITY AND CAPITAL RESOURCES
Operating
Our net cash flows provided by operating activities were $32 million for
the first quarter of 2003, compared to $49 million for the same period in 2002.
Cash provided from operations decreased primarily due to an increase in accounts
receivable, intercompany due to the timing of receipt of payments from our
affiliates partially offset by higher cash operating earnings.
Investing
Our cash flows used in investing activities was $10 million for the first
quarter of 2003 compared to $154 million for the same period in 2002. The
decrease from the prior year 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.
We continually review our generation portfolio and expected electrical
needs, and as a result, we could modify our plan for generation asset purchases,
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 may 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 $22 million in the
first quarter of 2003 compared to cash provided by financing activities of $108
million in the first quarter of 2002. Our principal financing activities for the
periods included issuances and redemptions of short-term borrowings from
Ameren's non-utility money pool and payment of dividends. The $109 million
increase in notes payable - intercompany in the first quarter of 2002 was
primarily due to funds used to purchase a combustion turbine generating unit
which was acquired in December 2001 but paid for in February 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-utility money pool agreement. However, the total amount
available to us at any time is reduced by the amount of borrowings from
16
Ameren by our affiliates and is increased to the extent other Ameren
non-regulated companies advance surplus funds to the non-utility money pool or
external sources are used by Ameren to increase the available amounts. At March
31, 2003, $600 million was available through the non-utility money pool not
including additional funds available through invested cash balances at Ameren
and uncommitted bank lines. The non-utility money pool was established to
coordinate and provide for short-term cash and working capital requirements of
Ameren's non-regulated activities and is administered by Ameren Services.
Interest is calculated at varying rates of interest depending on the composition
of internal and external funds in the non-utility money pool. The average
interest rate for borrowings from the non-utility money pool was 8.84% for the
three months ended March 31, 2003 (2002 - 4.30%). These rates are based on the
cost of Ameren's funds used to fund money pool advances. We incurred $5 million
in intercompany interest expense associated with outstanding borrowings from the
non-utility money pool for the three months ended March 31, 2003 (2002 - $1
million). At March 31, 2003, we had borrowings of $170 million from the
non-utility money pool (2002 - borrowings of $191 million).
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. The inability by us 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
and Ameren's current credit ratings, 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.
Indenture and Credit Agreement Provisions and Covenants
Ameren's and our financial agreements include customary default or cross
default provisions that could impact the continued availability of credit or
result in the acceleration of repayment. Ameren and its subsidiaries committed
credit facilities 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, Ameren's nor its other subsidiaries financing
arrangements contain credit rating triggers, except for three funded bank term
loans at AmerenCILCO totaling $105 million at March 31, 2003.
Ameren's committed credit facilities include provisions related to the
funded status of Ameren's pension plan. These provisions either require Ameren
to meet the minimum Employee Retirement Income Security Act of 1974 (ERISA)
funding requirements or limit the unfunded liability status of the plan. Under
the most restrictive of these provisions impacting Ameren facilities totaling
$400 million, an event of default will result if the unfunded liability status
(as defined in the underlying credit agreements) of Ameren's pension plan
exceeds $300 million in the aggregate. Based on the most recent valuation report
available to Ameren at December 31, 2002, which was based on January 2002 asset
and liability valuations, the unfunded liability status (as defined) was $31
million. While an updated valuation report will not be available until the
second half of 2003, Ameren believes that the unfunded liability status of its
pension plans (as defined) could exceed $300 million based on the investment
performance of the pension plan assets and interest rate changes since January
1, 2002. As a result, Ameren may need to renegotiate the facility provisions,
terminate or replace the affected facilities, or fund any unfunded liability
shortfall. Should Ameren elect to terminate these facilities, Ameren believes it
would otherwise have sufficient liquidity to manage its short-term funding
requirements.
At March 31, 2003, Ameren and its subsidiaries, including us, were in
compliance with their indenture and credit agreement provisions and covenants.
Off-Balance Sheet Arrangements
At March 31, 2003, neither Ameren Corporation, 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. At this time,
we do not expect to engage in any significant off-balance sheet financing
arrangements.
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 quarter of 2003 due
primarily to higher prices for natural gas;
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, including our
employees;
o Suspension of operations at two 1940's-era Ameren generating plants,
including two units at our Meredosia coal plant, to reduce operating
costs; and
o Reductions of 2003 expected capital expenditures.
We are also considering additional actions, including modifications to
active employee benefits, further staffing reductions and other initiatives.
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.
ACCOUNTING MATTERS
Critical Accounting Policies
Preparation of the financial statements and related disclosures in
compliance with generally accepted accounting principles requires the
application of appropriate technical accounting rules and guidance, as well as
the use of estimates. Our application of these policies involves judgments
regarding many factors, which, in and of themselves, could materially impact the
financial statements and disclosures. A future change in the assumptions or
judgments applied in determining the following matters, among others, could have
a material impact on future financial results. In the table below, we have
outlined those accounting policies that we believe are most difficult,
subjective or complex:
18
Accounting Policy Uncertainties Affecting Application
- ----------------- -----------------------------------
Environmental Costs
We accrue for all known environmental o Extent of contamination
contamination where remediation can be o Responsible party determination
reasonably estimated. However, we are o Approved methods for cleanup
contractually indemnified by AmerenCIPS for o Present and future legislation and governmental
remediation costs that we incur at the sites of regulations and standards
our coal plants relating to environmental o Results of ongoing research and development
contamination that occurred prior to the regarding environmental impacts
AmerenCIPS' transfer of the coal plants to us on
May 1, 2000.
Basis for Judgment
We determine the proper amounts to accrue for environmental contamination based
on internal and third party estimates of clean-up costs in the context of
current remediation standards and available technology.
Benefit Plan Accounting
Based on actuarial calculations, we accrue costs o Future rate of return on pension and other plan
of providing future employee benefits in assets
accordance with SFAS 87, 106 and 112. See Note o Interest rates used in valuing benefit
9 - Retirement Benefits to our Financial obligations
Statements in our 2002 Annual Report on Form o Healthcare cost trend rates
10-K. o Timing of employee retirements
o Future plan designs
Basis for Judgment
We utilize a third party consultant to assist us in evaluating and recording the
proper amount for future employee benefits. Our ultimate selection of the
discount rate, healthcare trend rate and expected rate of return on pension
assets is based on our review of available current, historical and projected
rates, as applicable.
Derivative Financial Instruments
We record all derivatives at their fair market o Market conditions in the energy industry,
value in accordance with SFAS 133. The especially the effects of price volatility on
identification and classification of a contractual commodity commitments
derivative and the fair value of such derivative o Regulatory and political environments and
must be determined. We designate certain requirements
derivatives as hedges of future cash flows. See o Fair value estimations on longer term contracts
Note 4 - Derivative Financial Instruments to our o Complexity of financial instruments and
Financial Statements under Item 1 of Part I of accounting rules
this report. o Effectiveness of our derivatives that have been
designated as hedges
Basis for Judgment
We determine whether a transaction is a derivative versus a normal purchase or
sale based on historical practice and our intention at the time we enter a
transaction. We utilize actively quoted prices, prices provided by external
sources, and prices based on internal models, and other valuation methods to
determine the fair market value of derivative financial instruments.
Impact of Future Accounting Pronouncements
See Note 1 - Summary of Significant Accounting Policies to our Financial
Statements under Item 1 of Part I of this report.
19
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 the issuance of 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 March 31, 2003,
we had $170 million of variable rate non-utility money pool borrowings
outstanding.
Utilizing our variable rate debt outstanding at March 31, 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 March 31, 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
We, along with other subsidiaries of Ameren, are a participant in Ameren's
defined benefit plans and postretirement benefit plans and are responsible for
our proportional share of the costs. Ameren's costs of providing
non-contributory defined benefit retirement and postretirement benefit plans are
dependent upon a number of factors, such as the rates of return on plan assets,
discount rate, the rate of increase in health care costs and contributions made
to the plans. The market value of Ameren's plan assets has been affected by
declines in the equity market since 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 Accumulated Other Comprehensive
Income (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
20
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
March 31, 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 first quarter of 2003:
=================================================================================================
- -------------------------------------------------------------------------------------------------
Fair value of contracts at beginning of period, net $ (a)
Contracts which were realized or otherwise settled during the period (a)
Changes in fair values attributable to changes in valuation techniques and
assumptions -
Fair value of new contracts entered into during the period -
Other changes in fair value 1
- -------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at end of period, net $ 1
=================================================================================================
(a) Less than $1 million.
Maturities of contracts as of March 31, 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) 1 - - 1
- ------------------------------------------------------------------------------------------------------------
Total $ (d) $ 1 $ - $ - $ 1
============================================================================================================
(a) Contracts of approximately 15% of the absolute fair value were with
non-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.
21
ITEM 4. Controls and Procedures.
(a) Evaluation of Disclosure Controls and Procedures
Within the 90 days prior to the date of this report, we carried out an
evaluation, under the supervision and with participation of our management,
including our chief executive officer and chief financial officer, of the
effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13a-14 under the Securities Exchange act of 1934, as
amended. Based upon that evaluation, the chief executive officer and chief
financial officer concluded that our disclosure controls and procedures are
effective in timely alerting them to material information relating to
AmerenEnergy Generating Company which is required to be included in our periodic
Securities and Exchange Commission filings.
(b) Change in Internal Controls
There have been no significant changes in our internal controls or in other
factors which could significantly affect internal controls subsequent to the
date we carried out our evaluation.
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;
o cost and availability of transmission capacity for the energy generated by
our generating facilities or required to satisfy energy sales made on our
behalf; and
22
o legal and administrative proceedings.
Given these uncertainties, undue reliance should not be placed on these
forward-looking statements. Except to the extent required by the federal
securities laws, we undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
23
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings.
Note 2 - Rate and Regulatory Matters to our Financial Statements under Item
1 of Part I of this report contains information on legal and administrative
proceedings which is incorporated by reference under this item.
ITEM 6. Exhibits and Reports on Form 8-K.
(a)(i) Exhibits filed herewith.
99.1 - Certificate of Chief Executive Officer required by
Section 906 of the Sarbanes - Oxley Act of 2002.
99.2 - Certificate of Chief Financial Officer required by
Section 906 of the Sarbanes-Oxley Act of 2002.
(a)(ii) Exhibits incorporated by reference.
10.1 - * 2003 Ameren Executive Incentive Plan (Ameren
Corporation quarterly report on Form 10-Q for the
quarter ended March 31, 2003, Exhibit 10.1).
* Management compensatory plan or arrangement.
(b) Reports on Form 8-K. AmerenEnergy Generating Company filed
no reports on Form 8-K during the quarterly period ended
March 31, 2003.
Note: Reports of Ameren Corporation on Forms 8-K, 10-Q and 10-K are
on file with the SEC under File Number 1-14756.
Reports of Central Illinois Public Service Company on Forms
8-K, 10-Q and 10-K are on file with the SEC under File Number
1-3672.
Reports of Union Electric Company on Forms 8-K, 10-Q and 10-K
are on file with the SEC under File Number 1-2967.
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: May 14, 2003
CERTIFICATIONS
I, Daniel F. Cole, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Ameren Energy
Generating Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
25
CERTIFICATIONS (CONTINUED)
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 14, 2003 /s/ Daniel F. Cole
------------------------------
Daniel F. Cole
President
(Principal Executive Officer)
I, Warner L. Baxter, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Ameren Energy
Generating Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
26
CERTIFICATIONS (CONTINUED)
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: May 14, 2003 /s/ Warner L. Baxter
-------------------------------
Warner L. Baxter
Senior Vice President,Finance
(Principal Financial Officer)
27