UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For Quarterly Period Ended 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 1-2967
UNION ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Missouri 43-0559760
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1901 Chouteau Avenue, St. Louis, Missouri 63103
(Address of principal executive offices and Zip Code)
Registrant's telephone number,
including area code: (314) 621-3222
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes (X). No ( ).
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, $5 par value, held by Ameren Corporation (parent company of the
registrant) - 102,123,834.
UNION ELECTRIC COMPANY
TABLE OF CONTENTS
Page
----
PART I Financial Information
ITEM 1. Financial Statements (Unaudited)
Consolidated Balance Sheet at March 31, 2003 and December 31, 2002................................... 2
Consolidated Statement of Income for the three months ended March 31, 2003 and 2002.................. 3
Consolidated Statement of Cash Flows for the three months ended March 31, 2003 and 2002.............. 4
Consolidated Statement of Common Stockholder's Equity for the three months ended March 31, 2003
and 2002............................................................................................. 5
Notes to Consolidated Financial Statements........................................................... 6
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................ 14
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk........................................... 24
ITEM 4. Controls and Procedures.............................................................................. 26
PART II Other Information
ITEM 1. Legal Proceedings.................................................................................... 28
ITEM 6. Exhibits and Reports on Form 8-K..................................................................... 28
SIGNATURE......................................................................................................... 30
CERTIFICATIONS.................................................................................................... 30
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.
1
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements.
UNION ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(Unaudited, in millions, except per share amounts)
March 31, December 31,
2003 2002
----------- ------------
ASSETS:
Property and plant, net $ 6,093 $ 5,991
Investments and other assets:
Nuclear decommissioning trust fund 172 172
Other assets 238 235
----------- ------------
Total investments and other assets 410 407
----------- ------------
Current assets:
Cash and cash equivalents 118 9
Accounts receivable - trade (less allowance for doubtful
accounts of $5 and $6, respectively) 171 171
Unbilled revenue 89 101
Miscellaneous accounts and notes receivable 54 49
Materials and supplies, at average cost 147 162
Other current assets 23 26
----------- ------------
Total current assets 602 518
----------- ------------
Regulatory assets 776 659
----------- ------------
Total Assets $ 7,881 $ 7,575
=========== ============
CAPITAL AND LIABILITIES:
Capitalization:
Common stock, $5 par value, 150.0 shares authorized -
102.1 shares outstanding $ 511 $ 511
Other paid-in capital, principally premium on common stock 702 702
Retained earnings 1,462 1,477
Accumulated other comprehensive income (59) (58)
----------- ------------
Total common stockholder's equity 2,616 2,632
----------- ------------
Preferred stock not subject to mandatory redemption 113 113
Long-term debt, net 1,862 1,687
----------- ------------
Total capitalization 4,591 4,432
----------- ------------
Current liabilities:
Current maturities of long-term debt 135 130
Short-term debt - 250
Intercompany notes payable 332 15
Accounts and wages payable 155 348
Accumulated deferred income taxes 3 2
Taxes accrued 178 118
Other current liabilities 96 94
----------- ------------
Total current liabilities 899 957
----------- ------------
Accumulated deferred income taxes 1,320 1,344
Accumulated deferred investment tax credits 120 121
Regulatory liabilities 114 121
Asset retirement obligation 391 174
Accrued pension liabilities 261 252
Other deferred credits and liabilities 185 174
----------- ------------
Total Capital and Liabilities $ 7,881 $ 7,575
=========== ============
See Notes to Consolidated Financial Statements.
2
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF INCOME
(Unaudited, in millions)
Three Months Ended
March 31,
-------------------------------
2003 2002
------------- -------------
OPERATING REVENUES:
Electric $ 555 $ 534
Gas 65 50
------------- -------------
Total operating revenues 620 584
------------- -------------
OPERATING EXPENSES:
Fuel and purchased power 141 144
Gas 39 32
Other operations and maintenance 186 184
Depreciation and amortization 70 72
Income taxes 38 28
Other taxes 53 52
------------- -------------
Total operating expenses 527 512
------------- -------------
OPERATING INCOME 93 72
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction - 1
Miscellaneous, net -
Miscellaneous income 1 6
Miscellaneous expense (1) (2)
Income taxes - (1)
------------- -------------
Total other income and (deductions) - 4
------------- -------------
INTEREST CHARGES:
Interest 26 27
Allowance for borrowed funds used during construction (1) (2)
------------- -------------
Net interest charges 25 25
------------- -------------
NET INCOME 68 51
PREFERRED STOCK DIVIDENDS 1 2
------------- -------------
NET INCOME AFTER PREFERRED STOCK DIVIDENDS $ 67 $ 49
============= =============
See Notes to Consolidated Financial Statements.
3
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited, in millions)
Three Months Ended
March 31,
------------------------------
2003 2002
------------ -------------
Cash Flows From Operating:
Net income $ 68 $ 51
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 70 72
Amortization of nuclear fuel 7 7
Amortization of debt issuance costs and premium/discounts 1 1
Allowance for funds used during construction (1) (3)
Deferred income taxes, net (5) (4)
Deferred investment tax credits, net (1) (2)
Other (1) (2)
Changes in assets and liabilities:
Receivables, net 7 55
Materials and supplies 15 14
Accounts and wages payable (193) (170)
Taxes accrued 60 54
Assets, other (9) (7)
Liabilities, other 26 19
------------ -------------
Net cash provided by operating activities 44 85
------------ -------------
Cash Flows From Investing:
Construction expenditures (101) (101)
Allowance for funds used during construction 1 3
Nuclear fuel expenditures - (5)
Intercompany notes receivable - 84
------------ -------------
Net cash used in investing activities (100) (19)
------------ -------------
Cash Flows From Financing:
Dividends on common stock (82) (76)
Dividends on preferred stock (1) (2)
Capital issuance costs (1) -
Redemptions:
Nuclear fuel lease (2) -
Short-term debt (250) (186)
Issuances:
Nuclear fuel lease - 3
Long-term debt 184 -
Intercompany notes payable 317 192
------------ -------------
Net cash provided by (used in) financing activities 165 (69)
------------ -------------
Net change in cash and cash equivalents 109 (3)
Cash and cash equivalents at beginning of year 9 15
------------ -------------
Cash and cash equivalents at end of period $ 118 $ 12
============ =============
Cash paid during the periods:
Interest $ 23 $ 19
Income taxes, net 7 4
See Notes to Consolidated Financial Statements.
4
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF COMMON STOCKHOLDER'S EQUITY
(Unaudited, in millions)
Three Months Ended
March 31,
--------------------------------
2003 2002
------------- -------------
Common stock $ 511 $ 511
Other paid-in capital 702 702
Retained earnings
Beginning balance 1,477 1,440
Net income 68 51
Common stock dividends (82) (76)
Preferred stock dividends (1) (2)
------------- -------------
1,462 1,413
------------- -------------
Accumulated other comprehensive income
Beginning balance - derivative financial instruments 4 1
Change in derivative financial instruments in current period (1) (2)
------------- -------------
3 (1)
------------- -------------
Beginning balance - minimum pension liability (62) -
Change in minimum pension liability in current period - -
------------- -------------
(62) -
------------- -------------
(59) (1)
------------- -------------
Total common stockholder's equity $2,616 $2,625
============= =============
Comprehensive income, net of taxes
Net income $ 68 $ 51
Unrealized net gain/(loss) on derivative hedging instruments,
net of income taxes of $- and $-, respectively - 1
Reclassification adjustments for gains/(losses) included in net income,
net of income taxes of $- and $(1), respectively (1) (3)
------------- -------------
Total comprehensive income, net of taxes $ 67 $ 49
============= =============
See Notes to Consolidated Financial Statements.
5
UNION ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
March 31, 2003
NOTE 1 - Summary of Significant Accounting Policies
General
Union Electric Company, headquartered in St. Louis, Missouri, is a
wholly-owned subsidiary of Ameren Corporation (Ameren) and operates as AmerenUE.
Our principal business is the rate-regulated generation, transmission and
distribution of electricity, and the rate-regulated distribution of natural gas
to residential, commercial, industrial and wholesale users in Missouri and
Illinois. Ameren is a public utility holding company registered with the
Securities and Exchange Commission (SEC) under the Public Utility Holding
Company Act of 1935 (PUHCA) and is also 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. In addition to us,
Ameren's principal subsidiaries and our affiliates are as follows:
o Central Illinois Public Service Company, which operates a rate-regulated
electric and natural gas transmission and distribution business in Illinois
as AmerenCIPS.
o Central Illinois Light Company, a subsidiary of CILCORP Inc. (CILCORP),
which operates a rate-regulated electric 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 AmerenEnergy Generating
Company (Generating Company), which operates non rate-regulated electric
generation in Missouri and Illinois, AmerenEnergy Marketing Company
(Marketing Company), which markets power for periods over one year,
AmerenEnergy Fuels and Services Company, which procures fuel and manages
the related risks for Ameren affiliated companies and AmerenEnergy Medina
Valley Cogen (No. 4), LLC, which indirectly owns a 40 megawatt, gas-fired
electric generation plant. On February 4, 2003, Ameren completed its
acquisition of AES Medina Valley Cogen (No. 4), LLC (Medina Valley) and
renamed it AmerenEnergy Medina Valley Cogen (No. 4), LLC.
o AmerenEnergy, Inc. (AmerenEnergy), which serves as a power marketing and
risk management agent for Ameren affiliated companies for transactions of
primarily less than one year.
o Electric Energy, Inc. (EEI), which operates electric generation and
transmission facilities in Illinois. We have a 40% ownership interest in
EEI and have accounted for it under the equity method of accounting.
Resources Company also owns a 20% interest in EEI.
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 AmerenUE, our, we or us, we are referring to Union
Electric Company and its subsidiary, Union Electric Development Corporation, on
a consolidated basis. Union Electric Development Corporation owns and invests in
civic and community development enterprises. In some cases, we are referring to
our agents, Ameren Energy and Ameren Energy Fuels and Services Company. All
significant intercompany transactions have been eliminated. All tabular dollar
amounts are in millions, unless otherwise indicated.
The accounting policies of AmerenUE conform to generally accepted
accounting principles in the United States (GAAP). Our financial statements
reflect all adjustments (which include normal, recurring adjustments) necessary,
in our opinion, for a fair presentation of our interim results. These statements
should be read in conjunction with the financial statements and the notes
thereto included in our 2002 Annual Report on Form 10-K.
The preparation of financial statements in conformity with GAAP requires
management to make certain estimates and assumptions. Such estimates and
assumptions affect reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of 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.
6
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 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 additional
asset retirement obligations of approximately $213 million and a net increase in
net property and plant of approximately $76 million related primarily to the
Callaway nuclear decommissioning costs and retirement costs for a river
structure. The difference between the net asset and the liability recorded upon
adoption of SFAS 143 related to rate-regulated assets was recorded as an
additional regulatory asset of approximately $136 million because we expect to
continue to recover in electric rates the cost of Callaway nuclear
decommissioning and other costs of removal. These asset retirement obligations
and associated assets are in addition to assets and liabilities of $174 million
we previously recorded related to our future obligations and funds accumulated
to decommission the Callaway nuclear plant. Asset retirement obligations also
increased during the quarter due to accretion of $4 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.
Historically, we have included an estimated cost of dismantling and
removing plant from service upon retirement. Because these estimated costs of
removal have been included in the cost of service upon which our present utility
rates are based, and with the expectation that this practice will continue in
the jurisdictions in which we operate, adoption of SFAS 143 did not result in
any change in the deprecation accounting practices of our rate-regulated
operations. We have estimated future removal costs embedded in accumulated
depreciation related to rate-regulated plant assets were approximately $534
million at March 31, 2003.
Emerging Issues Task Force (EITF) Issue No. 02-3 and EITF Issue No. 98-10
In the quarters ended September 30, 2002 and December 31, 2002, we adopted
the provisions of EITF 02-3, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities," that require revenues and costs associated with
certain energy contracts to be shown on a net basis in the income statement.
Prior to adopting EITF 02-3 and the rescission of EITF 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities," our
accounting practice was to present all settled energy purchase or sale contracts
within our power risk management program on a gross basis in Operating Revenues
- - Electric and in Operating Expenses - Fuel and Purchased Power. This meant that
revenues were recorded for the 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 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 $150 million, which reduced interchange
revenues and
7
purchased power 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
We accrue an estimate of electric and gas revenues for service rendered,
but unbilled, at the end of each accounting period.
Interchange revenues included in Operating Revenues - Electric were $102
million for the three months ended March 31, 2003 (2002 - $78 million).
Purchased Power
Purchased power included in Operating Expenses - Fuel and Purchased Power
was $45 million for the three months ended March 31, 2003 (2002 - $65 million).
Excise Taxes
Excise taxes on Missouri electric and gas, and Illinois gas customer bills
are imposed on us and are recorded gross in Operating Revenues and Other Taxes.
Excise taxes recorded in Operating Revenues and Other Taxes for the three months
ended March 31, 2003 were $23 million (2002 - $22 million). Excise taxes
applicable to Illinois electric customer bills are imposed on the consumer and
are recorded as tax collections payable and included in Taxes Accrued on the
Consolidated Balance Sheet.
NOTE 2 - Rate and Regulatory Matters
Intercompany Purchase of Electric Generating Facilities
As a part of the settlement of the Missouri electric rate case in 2002, we
committed to making certain infrastructure investments from January 1, 2002
through June 30, 2006. The requirements are expected to be satisfied in part by
the proposed purchase at net book value (approximately $260 million) by us of
approximately 550 megawatts of combustion turbine generating units at
Pinckneyville and Kinmundy, Illinois from Generating Company, which is subject
to receipt of necessary regulatory approvals. Approval by the Missouri Public
Service Commission (MoPSC) is not required in order for this purchase to occur.
However, the MoPSC has jurisdiction over our ability to recover the cost of the
purchased generating facilities from our electric customers in our rates. As
part of the settlement of the Missouri electric rate case in 2002, we are
subject to a rate moratorium providing for no changes in electric rates before
June 30, 2006, subject to certain statutory and other exceptions.
8
In February 2003, we sought approval from the Federal Energy Regulatory
Commission (FERC) and the Illinois Commerce Commission (ICC) to purchase the 550
megawatts from Generating Company. Several independent power producers have
objected to our request at the FERC based on a claim that the purchase 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 the Audrain
Facility, was a better resource for us to acquire as compared to the 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 purchase as to whether it is the
least cost resource for us and recommended that the ICC deny approval of the
purchase. We 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 purchase on competition in wholesale electric markets. We will
have an opportunity to file testimony addressing this issue at the hearing to be
scheduled. We can not 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 the MoPSC for Missouri's gas and electric
utilities. We 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. 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 us. In May 2003, we 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, cash flows or results of operations in the event that our
motion is denied.
Regional Transmission Organization
Since April 2002, we 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.
Until the tariffs and other material terms of ours and AmerenCIPS'
participation in GridAmerica, and GridAmerica's participation in the Midwest
ISO, are finalized and approved by the FERC, we are unable to
9
predict the impact that on-going regional transmission organization developments
will have on our financial position, results of operations or liquidity. Our
participation in GridAmerica is subject to MoPSC approval. An order from the
MoPSC is expected during 2003.
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, we filed our
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. We 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. We 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.
Illinois Gas
In November 2002, we filed a request with the ICC to increase annual rates
for natural gas service by approximately $4 million. The ICC has until October
2003 to render a decision on this gas case; however, the ICC Staff has
recommended an annual increase of approximately $2 million.
Missouri Gas
In May 2003, we expect to file a request with the MoPSC to increase annual
rates for natural gas service.
NOTE 3 - Related Party Transactions
We have transactions in the normal course of business with our parent,
Ameren, and its other subsidiaries. These transactions are primarily comprised
of power purchases and sales, as well as other services received or rendered.
Intercompany power purchases from joint dispatch and other agreements were
approximately $27 million for the three months ended March 31, 2003 (2002 - $27
million). Intercompany power sales totaled $32 million for the three months
ended March 31, 2003 (2002 - $20 million).
Interchange revenues from outside sales of available generation through
AmerenEnergy were $70 million for the three months ended March 31, 2003 (2002 -
$54 million). Purchased power derived from AmerenEnergy was $17 million for the
three months ended March 31, 2003 (2002 - $37 million).
Support services provided by our affiliates, Ameren Services and
AmerenEnergy, including wages, employee benefits and professional services are
based on actual costs incurred. For the three months ended
10
March 31, 2003, support services provided by Ameren Services and AmerenEnergy
included in Operating Expenses - Other Operations and Maintenance totaled $50
million (2002 - $48 million).
As of March 31, 2003, intercompany receivables included in Miscellaneous
Accounts and Notes Receivable were approximately $37 million (December 31, 2002
- - $25 million). As of March 31, 2003, intercompany payables included in Accounts
and Wages Payable totaled approximately $45 million (December 31, 2002 - $103
million).
We have the ability to borrow from Ameren and AmerenCIPS through a utility
money pool agreement. Ameren Services administers the utility money pool and
tracks internal and external funds separately. Internal funds are surplus funds
contributed to the utility money pool from participants. The primary source of
external funds for the utility money pool at March 31, 2003 was our commercial
paper program. Through the utility money pool we can access committed credit
facilities at Ameren and AmerenCIPS, which totaled $615 million at March 31,
2003. These facilities are in addition to our own $79 million in committed
credit facilities. The total amount available to us at any given time from the
utility money pool is reduced by the amount of borrowings by our affiliates, but
increased to the extent Ameren, AmerenCIPS or Ameren Services have surplus funds
and the availability of other external borrowing sources. Surplus funds
providing additional liquidity available to us through the utility money pool
totaled $260 million at March 31, 2003. The availability of funds is also
determined by funding requirement limits established by the PUHCA. We, along
with AmerenCIPS and Ameren Services, rely on the utility money pool to
coordinate and provide for certain short-term cash and working capital
requirements. Borrowers receiving a loan under the utility money pool agreement
must repay the principal amount of such loan, together with accrued interest.
Interest is calculated at varying rates of interest depending on the composition
of internal and external funds in the utility money pool. For the three months
ended March 31, 2003, the average interest rate for the utility money pool was
1.32% (2002 - 1.79%). At March 31, 2003, we had outstanding intercompany
payables of $332 million, sourced by internal funds through the utility money
pool (December 31, 2002 - $15 million).
On April 1, 2003, we entered into an additional 364-day committed credit
facility totaling $75 million to be used for general corporate purposes,
including support of commercial paper programs. This facility makes borrowings
available at various interest rates based on LIBOR, agreed rates and other
options. Ameren and AmerenCIPS can access this facility through the utility
money pool.
NOTE 4 - Derivative Financial Instruments
As of March 31, 2003, we recorded the fair value of derivative financial
instrument assets of $9 million in Other Assets and the fair value of derivative
financial instrument liabilities of $3 million in Other Deferred Credits and
Liabilities.
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 $1 million loss for the three months
ended March 31, 2003 (2002 - $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 net gain of approximately $1 million (less than $1 million, net
of taxes).
We also hold two call options for coal with two suppliers. These options to
purchase coal expire October 2003 and July 2005. As of March 31, 2003, a
mark-to-market gain of approximately $6 million ($4 million, net of taxes)
associated with these options was included in OCI. The final value of the
options will be recognized as a reduction in fuel costs as the hedged coal is
burned.
Other Derivatives
We enter into option transactions to manage our positions in sulfur dioxide
allowances, coal and electricity. Most of these transactions are treated as
non-hedge transactions under SFAS 133. The net
11
change in the market value of these options is recorded as Miscellaneous, Net in
the income statement. The net change in the market values of sulfur dioxide,
coal and electricity options was a gain of $0.1 million for the three months
ended March 31, 2003 (2002 - gain of $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 $10,494 $10,294
Gas 271 268
Other 37 36
- --------------------------------------------------------------------------------
10,802 10,598
Less accumulated depreciation and amortization 5,088 4,968
- --------------------------------------------------------------------------------
5,714 5,630
Construction work in progress:
Nuclear fuel in process 82 81
Other 297 280
- --------------------------------------------------------------------------------
Property and plant, net $ 6,093 $5,991
- --------------------------------------------------------------------------------
NOTE 6 - Debt Financings
In August 2002, our shelf registration statement filed with the SEC on Form
S-3 was declared effective. This statement authorized the offering from time to
time of up to $750 million of various forms of long-term debt and trust
preferred securities to refinance existing debt and preferred stock, and for
general corporate purposes, including the repayment of short-term debt incurred
to finance construction expenditures and other working capital needs.
In March 2003, we issued, pursuant to the shelf registration, $184 million
of 5.50% Senior Secured Notes due March 15, 2034. We received net proceeds after
fees of $180 million, which, along with other funds, were used to redeem $104
million principal amount of outstanding 8.25% first mortgage bonds due October
15, 2022, at a redemption price of 103.61% of par, plus accrued interest, in
April 2003, prior to maturity, and to repay short-term debt incurred to pay at
maturity $75 million principal amount of 8.33% first mortgage bonds that were
due in December 2002.
In April 2003, we issued, pursuant to the shelf registration, $114 million
of 4.75% Senior Secured Notes due April 1, 2015. We received net proceeds after
fees of $113 million, which, along with other funds, were used to redeem $85
million principal amount of outstanding 8.00% first mortgage bonds due December
15, 2022, at a redemption price of 103.38% of par, plus accrued interest, prior
to maturity, and to reduce short-term money pool debt.
We may sell all, or a portion of, the remaining registered securities under
our shelf registration statement if warranted by market conditions and our
capital requirements. Any offer and sale will be made only by means of a
prospectus meeting the requirements of the Securities Act of 1933 and the rules
and regulations thereunder. At April 30, 2003, the amount remaining on the shelf
registration statement was $279 million.
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 premium or discounts for the
three months ended March 31, 2003 were $1 million (2002 - $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.
12
NOTE 7 - Miscellaneous, Net
Miscellaneous, net for the three months ended March 31, 2003 and 2002
consisted of the following:
================================================================================
Three Months
- --------------------------------------------------------------------------------
2003 2002
Miscellaneous income:
Equity in earnings of subsidiaries $ 1 $ 1
Other - 5
- --------------------------------------------------------------------------------
Total miscellaneous income $ 1 $ 6
================================================================================
Miscellaneous expense:
Other $ (1) $ (2)
- --------------------------------------------------------------------------------
Total miscellaneous expense $ (1) $ (2)
================================================================================
13
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
OVERVIEW
Union Electric Company, headquartered in St. Louis, Missouri, is a
wholly-owned subsidiary of Ameren Corporation (Ameren) and operates as AmerenUE.
Our principal business is the rate-regulated generation, transmission and
distribution of electricity, and the rate-regulated distribution of natural gas
to residential, commercial, industrial and wholesale users in Missouri and
Illinois. Ameren is a public utility holding company registered with the
Securities and Exchange Commission (SEC) under the Public Utility Holding
Company Act of 1935 (PUHCA) and is also 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. In addition to us,
Ameren's principal subsidiaries and our affiliates are as follows:
o Central Illinois Public Service Company, which operates a rate-regulated
electric and natural gas transmission and distribution business in Illinois
as AmerenCIPS.
o Central Illinois Light Company, a subsidiary of CILCORP Inc. (CILCORP),
which operates a rate-regulated electric 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 AmerenEnergy Generating
Company (Generating Company), which operates non rate-regulated electric
generation in Missouri and Illinois, AmerenEnergy Marketing Company
(Marketing Company), which markets power for periods over one year,
AmerenEnergy Fuels and Services Company, which procures fuel and manages
the related risks for Ameren affiliated companies and AmerenEnergy Medina
Valley Cogen (No. 4), LLC, which indirectly owns a 40 megawatt, gas-fired
electric generation plant. On February 4, 2003, Ameren completed its
acquisition of AES Medina Valley Cogen (No. 4), LLC (Medina Valley) and
renamed it AmerenEnergy Medina Valley Cogen (No. 4), LLC. See Recent
Developments for further information.
o AmerenEnergy, Inc. (AmerenEnergy), which serves as a power marketing and
risk management agent for Ameren affiliated companies for transactions of
primarily less than one year.
o Electric Energy, Inc. (EEI), which operates electric generation and
transmission facilities in Illinois. We have a 40% ownership interest in
EEI and have accounted for it under the equity method of accounting.
Resources Company also owns a 20% interest in EEI.
o Ameren Services Company (Ameren Services), which provides shared support
services to Ameren and its subsidiaries, including us. Charges are based
upon the actual costs incurred by Ameren Services, as required by the
PUHCA.
You should read the following discussion and analysis in conjunction with:
o The financial statements and related notes included in this Quarterly
Report on Form 10-Q.
o Management's Discussion and Analysis of Financial Condition and Results of
Operations that appears in our Annual Report on Form 10-K for the period
ended December 31, 2002.
o The audited financial statements and related notes that appear in our
Annual Report on Form 10-K for the period ended December 31, 2002.
When we refer to AmerenUE, our, we or us, we are referring to Union
Electric Company and its subsidiary, Union Electric Development Corporation on a
consolidated basis. Union Electric Development Corporation owns and invests in
civic and community development enterprises. In some cases, we are referring to
our agents, Ameren Energy and Ameren Energy Fuels and Services Company. All
tabular dollar amounts are in millions, unless otherwise indicated.
Our results of operations and financial position are impacted by many
factors, including both controllable and uncontrollable factors. Weather,
economic conditions and the actions of key customers or competitors can
significantly impact the demand for our services. Our results are also impacted
by seasonal fluctuations caused by winter heating and summer cooling demand.
With nearly all of our revenues directly subject to regulation by various state
and federal agencies, decisions by regulators can have a material impact on the
price we charge for our services. We principally utilize coal, nuclear fuel,
natural gas and oil in our operations. The prices for these commodities can
fluctuate significantly due to the world economic and political environment,
weather, production levels and many other factors. We do not have fuel recovery
mechanisms in Missouri or Illinois for our electric utility businesses, but we
do have gas cost recovery mechanisms in each state for our gas utility
businesses. In addition, our electric rates in
14
Missouri and Illinois are largely set through 2006. 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 transmission and distribution systems, 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 $68 million in the first quarter of 2003 from
$51 million in the first quarter of 2002. The increase was primarily due to
favorable weather conditions in our service territory ($15 million, net of
taxes), increased electric margin due to greater use of low-cost generating
units to serve native customers ($2 million, net of taxes) and increased
earnings from interchange sales ($17 million, net of taxes) due to approximately
90% higher power prices in the energy markets than the prior period.
Weather-sensitive residential electric kilowatthour sales increased by 14%,
commercial electric kilowatthour sales increased by 8% and gas sales increased
by 7% in the first quarter of 2003 compared to the first quarter of 2002.
Partially offsetting the benefit on net income of weather, interchange margin
and generation availability in the first quarter of 2003 were higher employee
benefit costs ($4 million, net of taxes) related to benefit plan performance and
increasing healthcare costs, no sales of emission credits in the first quarter
of 2003 ($8 million, net of taxes) and the impact of the 2002 settlement of the
Missouri electric rate case ($4 million, net of taxes).
Recent Developments
Acquisitions
On January 31, 2003, Ameren completed its acquisition of all of the
outstanding common stock of CILCORP from The AES Corporation. CILCORP is the
parent company of Peoria, Illinois-based Central Illinois Light Company, which
operated as CILCO. With the acquisition, CILCO became an 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 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.
Debt Issuances
In March 2003, we issued $184 million of 5.50% Senior Secured Notes due
March 15, 2034. We received net proceeds after fees of $180 million, which,
along with other funds, were used to redeem $104 million principal amount of
outstanding 8.25% first mortgage bonds due October 15, 2022, at a redemption
15
price of 103.61% of par, plus accrued interest, in April 2003, prior to
maturity, and to repay short-term debt incurred to pay at maturity $75 million
principal amount of 8.33% first mortgage bonds due in December 2002.
In April 2003, we issued $114 million of 4.75% Senior Secured Notes due
April 1, 2015. We received net proceeds after fees of $113 million, which, along
with other funds, were used to redeem $85 million principal amount of
outstanding 8.00% first mortgage bonds due December 15, 2022, at a redemption
price of 103.38% of par, plus accrued interest, prior to maturity, and to reduce
short-term money pool debt.
Credit Ratings
In April 2002, as a result of our then pending Missouri electric earnings
complaint case and the CILCORP transaction and related assumption of debt,
credit rating agencies placed Ameren'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, AmerenUE and AmerenCIPS and increased
the ratings of Generating Company, CILCORP and AmerenCILCO. At the same time,
Standard & Poor's changed the outlook assigned to all of Ameren's and its
subsidiaries' ratings to stable. Moody's also lowered Ameren'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.
16
Electric Operations
The following table represents the favorable (unfavorable) variation on
electric margins for the three months ended March 31, 2003 from the comparable
period in 2002:
================================================================================
Three Months
- --------------------------------------------------------------------------------
Electric Revenues:
Interchange revenues $ 24
Effect of weather (estimate) 21
Rate reductions (11)
Growth and other (estimate) (13)
- --------------------------------------------------------------------------------
Total variation in electric operating revenues 21
Fuel and Purchased Power:
Fuel:
Generation $ (16)
Price -
Generation efficiencies and other (1)
Purchased power 20
- --------------------------------------------------------------------------------
Total variation in fuel and purchased power 3
================================================================================
Change in electric margin $ 24
================================================================================
Electric margin increased $24 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 attributable to increased interchange
margins and higher native load customer demand resulting from colder winter
weather. Residential kilowatthour sales increased 14% and commercial
kilowatthour sales increased 8% in the first quarter of 2003. Interchange
margins increased due to improved power prices in the energy markets and solid
low-cost generation availability. 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. Partially offsetting the
benefit of these increases in electric margin were an 8% decline in industrial
sales in the first quarter of 2003 due to the continued soft economy, no sales
of emission credits in the first quarter of 2003 (2002 - $13 million) and rate
reductions in Missouri relating to a 2002 rate settlement ($11 million).
Revenues will continue to be negatively affected by the settlement of the
Missouri electric rate case, which requires the phase-in of $30 million of
electric rate reductions effective April 1, 2003 and $30 million effective April
1, 2004.
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 $150
million, which reduced interchange revenues and purchased power costs by equal
amounts. See Note 1 - Summary of Significant Accounting Policies to our
Consolidated Financial Statements under Item 1 of Part I of this report for
further information.
Gas Operations
Our gas margin increased $8 million in the first quarter of 2003, compared
to the first quarter of 2002, with revenues increasing by $15 million and costs
increasing by $7 million. The increase in margin was primarily due to increased
customer demand resulting from colder winter weather and the prior year's warmer
than normal conditions.
Other Operating Expenses
Other Operations and Maintenance
Other operations and maintenance expenses increased $2 million in the first
quarter of 2003, compared to the first quarter of 2002, primarily due to higher
employee benefit costs related to increasing healthcare costs and the investment
performance of employee benefit plans' assets ($7 million), partially offset by
higher tree-trimming expenses in the first quarter of 2002, which were
accelerated, in part, to take advantage of mild weather.
17
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 Consolidated Financial Statements under Item 1 of Part I of this report for
further information.
Depreciation and Amortization
Depreciation and amortization expenses decreased $2 million in the first
quarter of 2003 compared to the prior period. The decrease was primarily due to
a reduction of depreciation rates based on an updated analysis of asset values,
service lives and accumulated depreciation levels that was included in our 2002
Missouri electric rate case settlement ($5 million), partially offset by capital
additions in 2002.
Income Taxes
Income tax expense increased $9 million in the first quarter of 2003,
compared to the 2002 period, primarily due to higher pretax income.
Other Taxes
Other taxes expense increased $1 million in the first quarter of 2003,
compared to the 2002 period, primarily due to an increase in gross receipts
taxes related to increased native sales.
Other Income and Deductions
Other income and deductions (excluding income taxes) for the three months
ended March 31, 2003 decreased $4 million, compared to the first quarter of 2002
primarily due to decreased gains on derivative contracts. See Note 7 -
Miscellaneous, Net to our Consolidated Financial Statements under Item 1 of Part
I of this report for further information.
Interest
Interest expense decreased $1 million in the first quarter of 2003 compared
to the 2002 period, primarily due to lower interest rates on new issuances of
first mortgage bonds as compared to the issues redeemed.
LIQUIDITY AND CAPITAL RESOURCES
Operating
Our cash flows provided by operating activities were $44 million for the
first quarter of 2003, compared to $85 million for the same period in 2002. Cash
provided by operations decreased in the first quarter of 2003, primarily as a
result of the timing of receipts on receivables, net and payments on accounts
and wages payable, partially offset by higher cash earnings from higher electric
and gas margins.
Our tariff-based gross margins continue to be our principal source of cash
from operating activities. Our diversified retail customer mix of rate-regulated
residential, commercial and industrial classes and a commodity mix of gas and
electric service provide a reasonably predictable source of cash flows. In
addition, we plan to utilize short-term debt to support normal operations and
other temporary capital requirements.
Investing
Our net cash used in investing activities was $100 million in the first
quarter of 2003 compared to $19 million for the same period in 2002. The
increase over the prior year period was due to first quarter of 2002 receipt of
$84 million previously invested in the utility money pool. In the first quarter
of 2003, construction expenditures were $101 million (2002 - $101 million),
primarily related to various upgrades at our power plants. Our capital
expenditures are expected to approximate $485 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
18
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 provided by financing activities totaled $165 million in the
first quarter of 2003 compared to cash flows used in financing activities of $69
million in the first quarter of 2002. Our principal financing activities for the
first quarter of 2003 included the issuances of intercompany notes payable and
long-term debt, partially offset by the redemption of short-term debt and the
payment of dividends.
We are authorized by the SEC under the PUHCA to have up to $1 billion of
short-term unsecured debt instruments outstanding at any time.
Short-Term Debt and Liquidity
Short-term debt consists of commercial paper, intercompany borrowings
through Ameren's utility money pool and bank loans (maturities generally within
1 to 45 days). At March 31, 2003, Ameren and its subsidiaries had committed
credit facilities, expiring at various dates between 2003 and 2005, totaling
$694 million, excluding AmerenCILCO facilities of $60 million, EEI facilities of
$45 million and our nuclear fuel lease facilities of $120 million. This amount
includes $79 million of our committed credit facilities and $615 million of
committed credit facilities at Ameren and AmerenCIPS. We access these combined
facilities through Ameren's utility money pool arrangement. AmerenCIPS and
Ameren Services may also borrow under this arrangement. These committed credit
facilities are used to support our commercial paper program, under which no
amounts were outstanding at March 31, 2003. At March 31, 2003, $694 million was
unused and available under these committed credit facilities.
Subject to the receipt of regulatory approval, which is being pursued,
AmerenCILCO will participate in Ameren's utility money pool arrangement. Under
this arrangement, AmerenCILCO will have access to up to $694 million of
additional committed liquidity, subject to reduction based on the use by other
utility money pool participants, but increased to the extent other pool
participants have surplus cash balances, which may be used to fund pool needs.
At March 31, 2003, AmerenCILCO had committed credit facilities, expiring at
various dates during 2003, totaling $60 million, one of which totaling $25
million was subsequently renewed to 2004.
On April 1, 2003, we entered into an additional 364-day committed credit
facility totaling $75 million to be used for general corporate purposes,
including support of commercial paper programs. This facility makes borrowings
available at various interest rates based on LIBOR, agreed rates and other
options. Ameren and AmerenCIPS can access this facility through the utility
money pool.
EEI also has two bank credit agreements totaling $45 million that expire in
2003. At March 31, 2003, $32 million was unused and available under these
committed credit facilities.
We also have a lease agreement that provides for the financing of nuclear
fuel. At March 31, 2003, the maximum amount that could be financed under the
agreement was $120 million. At March 31, 2003, $111 million was financed under
the lease.
In addition to committed credit facilities, a further source of liquidity
for Ameren is available cash and cash equivalents. At March 31, 2003, Ameren had
$260 million of cash, all of which was available for borrowings by us under the
utility money pool. In the first quarter of 2003, Ameren paid a total of $488
million of cash on hand, including related acquisition costs, net of cash
acquired, to acquire CILCORP and Medina Valley.
We 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
current credit ratings, we believe that we will continue to have access to the
capital markets. However, events beyond our control may create uncertainty
19
in the capital markets such that our cost of capital would increase or our
ability to access the capital markets would be adversely affected.
Financial Agreement Provisions and Covenants
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's 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 and its subsidiaries' committed credit facilities include
provisions related to the funded status of Ameren's pension plan. These
provisions either require Ameren to meet minimum Employee Retirement Income
Security Act of 1974 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 financial agreement provisions and covenants.
Debt Financings
See Note 6 - Debt Financings to our Consolidated Financial Statements under
Item 1 of Part I of this report for information about financings during the
first quarter of 2003.
Off-Balance Sheet Arrangements
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.
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 A rate settlement approved in 2002 by the Missouri Public Service
Commission that required electric rate reductions of $50 million on April
1, 2002 and $30 million on April 1, 2003 with an additional $30 million
reduction required for April 1, 2004;
o The adverse effects of rising employee benefit costs, higher insurance
costs and increased security costs associated with additional measures we
have taken, or may have to take, at our Callaway nuclear plant related to
world events; and
o An assumed return to more normal weather patterns relative to 2002.
20
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 230 of our employees and
additional employees providing support functions to us through Ameren
Services;
o Modifications to retiree employee benefit plans to increase co-payments and
limit our overall cost;
o A wage freeze in 2003 for all management employees;
o Suspension of operations at two 1940's-era Ameren generating plants,
including our Venice, Illinois plant, to reduce operating costs; and
o Reductions of 2003 expected capital expenditures.
We are pursuing an annual gas rate increase of approximately $4 million in
Illinois and we expect to file an annual gas rate increase in Missouri. Ameren
is also considering additional actions, including modifications to active
employee benefits, further staffing reductions and other initiatives.
In early May 2003, our service territory experienced several severe storms
that damaged parts of our transmission and distribution system. As a result, we
expect to incur increased costs in the quarter ending June 30, 2003 for repairs
required to our system. We are currently unable to estimate the impact on our
future financial position, results of operations or cash flows.
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 Consolidated 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:
Accounting Policy Uncertainties Affecting Application
- ----------------- -----------------------------------
Regulatory Mechanisms and Cost Recovery
We defer costs as regulatory assets in o Regulatory environment, external regulatory
accordance with SFAS 71 and make decisions and requirements
investments that we assume we will be able o Anticipated future regulatory decisions and
to collect in future rates. their impact
o Impact of deregulation and competition on
ratemaking process and ability to recover costs
Basis for Judgment
We determine that costs are recoverable based on previous rulings by state
regulatory authorities in jurisdictions where we operate or other factors
that lead us to believe that cost recovery is probable.
21
Accounting Policy (Continued) Uncertainties Affecting Application (Continued)
- ----------------------------- -----------------------------------------------
Nuclear Plant Decommissioning Costs
In our rates and earnings we assume the o Estimates of future decommissioning costs
Department of Energy will develop a permanent o Availability of facilities for waste disposal
storage site for spent nuclear fuel, the o Approved methods for waste disposal and
Callaway nuclear plant will have a useful decommissioning
life of 40 years and estimated costs of o Useful lives of nuclear power plants
approximately $515 million to dismantle the
plant are accurate. See Note 15 - Callaway
Nuclear Plant to our Financial Statements in
our 2002 Annual Report on Form 10-K.
Basis for Judgment
We determine that decommissioning costs are reasonable, or require
adjustment, based on third party decommissioning studies that are completed
every three years, the evaluation of our facilities by our engineers and the
monitoring of industry trends.
Environmental Costs
We accrue for all known environmental o Extent of contamination
contamination where remediation can be o Responsible party determination
reasonably estimated, but some of our o Approved methods for cleanup
operations have existed for over 100 years o Present and future legislation and governmental
and previous contamination may be unknown to regulations and standards
us. o Results of ongoing research and development
regarding environmental impacts
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.
Unbilled Revenue
At the end of each period, we estimate, based o Projecting customer energy usage
on expected usage, the amount of revenue to o Estimating impacts of weather and other
record for services that have been provided usage-affecting factors for the unbilled period
to customers, but not billed. This period
can be up to one month.
Basis for Judgment
We determine the proper amount of unbilled revenue to accrue each period
based on the volume of energy delivered as valued by a model of billing
cycles and historical usage rates and growth by customer class for our
service area, as adjusted for the modeled impact of seasonal and weather
variations based on historical results.
22
Accounting Policy (Continued) Uncertainties Affecting Application (Continued)
- ----------------------------- -----------------------------------------------
Benefit Plan Accounting
Based on actuarial calculations, we accrue o Future rate of return on pension and other plan
costs of providing future employee benefits assets
in accordance with SFAS 87, 106 and 112. See o Interest rates used in valuing benefit
Note 13 - Retirement Benefits to our obligations
Financial Statements in our 2002 Annual o Healthcare cost trend rates
Report on Form 10-K. o Timing of employee retirements
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 o Market conditions in the energy industry,
market value in accordance with SFAS 133. especially the effects of price volatility on
The identification and classification of a contractual commodity commitments
derivative and the fair value of such o Regulatory and political environments and
derivative must be determined. We designate requirements
certain derivatives as hedges of future cash o Fair value estimations on longer term contracts
flows. See Note 4 - Derivative Financial o Complexity of financial instruments and
Instruments to our Consolidated Financial accounting rules
Statements under Item 1 of Part I of this o Effectiveness of our derivatives that have been
report. 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
Consolidated Financial Statements under Item 1 of Part I of this report for
information.
23
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk.
Market risk represents the risk of changes in value of a physical asset or
financial instrument, derivative or non-derivative, caused by fluctuations in
market variables (e.g. interest rates, etc.). The following discussion of
Ameren's, including AmerenUE's, risk management activities includes
"forward-looking" statements that involve risks and uncertainties. Actual
results could differ materially from those projected in the "forward-looking"
statements. Ameren handles market risks in accordance with established policies,
which may include entering into various derivative transactions. In the normal
course of business, Ameren and AmerenUE 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.
Ameren's risk management objective is to optimize its physical generating
assets within prudent risk parameters. Our risk management policies are set by a
Risk Management Steering Committee, which is comprised of senior-level Ameren
officers.
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated
with both long-term and short-term variable-rate debt, fixed-rate debt and
commercial paper. 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.
Utilizing our debt outstanding at March 31, 2003, if interest rates
increase by 1%, our annual interest expense would increase by approximately $9
million and net income would decrease by approximately $6 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 trade accounts receivables and executory contracts with market
risk exposures. The risk associated with trade receivables is mitigated by the
large number of customers in a broad range of industry groups comprising our
customer base. No customer represents greater than 10% of our accounts
receivable. Our revenues are primarily derived from sales of electricity and
natural gas to customers in Missouri and Illinois. 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)
24
of $102 million, net of taxes. Our portion of this charge to OCI was $62
million, net of taxes. The amount of the liability was the result of asset
returns experienced through 2002, interest rates and Ameren's contributions to
the plan during 2002. Neither Ameren's nor our portion of the minimum pension
liability changed at 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 Consolidated Balance Sheet.
We also maintain trust funds, as required by the Nuclear Regulatory
Commission and Missouri and Illinois state laws, to fund certain costs of
nuclear decommissioning. By maintaining a portfolio that includes long-term
equity investments, we seek to maximize the returns to be utilized to fund
nuclear decommissioning costs. However, the equity securities included in our
portfolio are exposed to price fluctuations in equity markets and the
fixed-rate, fixed-income securities are exposed to changes in interest rates. We
actively monitor our portfolio by benchmarking the performance of our
investments against certain indices and by maintaining, and periodically
reviewing, established target allocation percentages of the assets of our trusts
to various investment options. Our exposure to equity price market risk is, in
large part, mitigated due to the fact that we are currently allowed to recover
decommissioning costs in our rates.
Fair Value of Contracts
We utilize derivatives principally to manage the risk of changes in market
prices for natural gas, fuel, electricity and emission credits. Price
fluctuations in natural gas, fuel and electricity cause:
o an unrealized appreciation or depreciation of our firm commitments to
purchase or sell when purchase or sales prices under the firm commitment
are compared with current commodity prices;
o market values of fuel and natural gas inventories or purchased power to
differ from the cost of those commodities under the 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
Consolidated Financial Statements under Item 1 of Part I of this report for
further information.
The following 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 $ 6
Contracts which were realized or otherwise settled during the period (1)
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 -
- -------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at end of period, net $ 5
- -------------------------------------------------------------------------------------------------------------
Maturities of contracts as of March 31, 2003 were as follows:
======================================================================================================================
Maturity Maturity
less than Maturity Maturity in excess Total fair
Sources of fair value 1 year 1-3 years 4-5 years of 5 years value (a)
- ----------------------------------------------------------------------------------------------------------------------
Prices actively quoted $ - $ - $ - $ - $ -
Prices provided by other external sources (b) 1 - - - 1
Prices based on models and other valuation
methods (c) 4 1 (1) - 4
- ----------------------------------------------------------------------------------------------------------------------
Total $ 5 $ 1 $ (1) $ - $ 5
- ----------------------------------------------------------------------------------------------------------------------
(a) Contracts of approximately 5% 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 coal and sulfur dioxide options valued based on a Black-Scholes
model that includes information from external sources and our estimates.
25
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 AmerenUE
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 some 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 the stipulation and agreement relating to our Missouri
electric excess earnings complaint case and other regulatory actions,
including changes in regulatory policy;
o changes in laws and other governmental actions, including monetary and
fiscal policies;
o the impact on us of current regulations related to the opportunity for
customers to choose alternative energy suppliers in Illinois;
o the effects of increased competition in the future due to, among other
things, deregulation of certain aspects of our business at both the
state and federal levels;
o the effects of participation in a Federal Energy Regulatory
Commission-approved Regional Transmission Organization, including
activities associated with the Midwest System Independent Operator;
o availability and future market prices for fuel for the production of
electricity, such as coal and natural gas, purchased power,
electricity and natural gas 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 average rates 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 operation of nuclear power facilities and decommissioning costs;
o the effects of strategic initiatives, including acquisitions and
divestitures;
26
o the impact of current environmental regulations on utilities and
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 Ameren's or
our access to necessary capital more difficult or costly;
o competition from other generating facilities, including new facilities
that may be developed in the future;
o cost and availability of transmission capacity for the energy
generated by our generating facilities or required to satisfy our
energy sales; and
o legal and administrative proceedings.
Given these uncertainties, undue reliance should not be placed on these
forward-looking statements. Except to the extent required by the federal
securities laws, we undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
27
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
Reference is made to Note 14 under Item 8 "Financial Statements and
Supplementary Data" in Part II of our 2002 Annual Report on Form 10-K and Note 7
under Item 8 "Financial Statements and Supplementary Data" in Part II of the
2002 Annual Report on Form 10-K of our affiliates, CILCORP Inc. and Central
Illinois Light Company, operating as AmerenCILCO, for a discussion of a number
of lawsuits that name our affiliates, Central Illinois Public Service Company,
operating as AmerenCIPS and AmerenCILCO, our parent, Ameren Corporation and us
(which we refer to as the Ameren companies), along with numerous other parties,
as defendants that have been filed by plaintiffs claiming varying degrees of
injury from asbestos exposure. Since the filing of the 2002 Annual Reports on
Form 10-K, 25 additional lawsuits have been filed against AmerenCIPS and
AmerenUE, but no additional lawsuits have been filed against AmerenCILCO. These
lawsuits, like the previous cases, were mostly filed in the Circuit Court of
Madison County, Illinois, involve a large number of total defendants and seek
unspecified damages in excess of $50,000, which, if proved, typically would be
shared among the named defendants. Also since the filing of the 2002 Annual
Reports on Form 10-K, the Ameren companies have been voluntarily dismissed in 58
cases and have settled six cases.
To date, a total of 152 asbestos-related lawsuits have been filed against
the Ameren companies, of which 72 are pending, 16 have been settled and 64 have
been dismissed. We believe that the final disposition of these proceedings will
not have a material adverse effect on our financial position, results of
operations or liquidity.
Note 2 - Rate and Regulatory Matters to our Consolidated Financial
Statements under Item 1 of Part I of this report contains additional information
on legal and administrative proceedings which is incorporated by reference under
this item.
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.
28
(b) Reports on Form 8-K. Union Electric Company filed the following
report on Form 8-K during the quarterly period ended March 31,
2003:
======================================================================
Items Reported Financial
Date of Report Statements Filed
----------------------------------------------------------------------
March 10, 2003 5, 7 None
Note: Reports of Ameren Corporation on Forms 8-K, 10-Q and 10-K are on
file with the SEC under File Number 1-4756.
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 AmerenEnergy Generating Company on Forms 8-K, 10-Q and
10-K are on file with the SEC under File Number 333-56594.
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.
29
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.
UNION ELECTRIC COMPANY
(Registrant)
By /s/ Martin J. Lyons
-------------------------------
Martin J. Lyons
Vice President and Controller
(Principal Accounting Officer)
Date: May 14, 2003
CERTIFICATIONS
I, Charles W. Mueller, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Union Electric
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
30
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/ Charles W. Mueller
------------------------------------
Charles W. Mueller
Chairman and Chief Executive Officer
(Principal Executive Officer)
I, Warner L. Baxter, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Union Electric
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
31
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)
32