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 June 30, 2003
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For The Transition Period From to
Commission file number 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 August 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
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PART I Financial Information
ITEM 1. Financial Statements (Unaudited)
Consolidated Balance Sheet at June 30, 2003 and December 31, 2002..................................... 2
Consolidated Statement of Income for the three and six months ended June 30, 2003 and 2002............ 3
Consolidated Statement of Cash Flows for the six months ended June 30, 2003 and 2002.................. 4
Consolidated Statement of Common Stockholder's Equity for the three and six months ended June 30,
2003 and 2002......................................................................................... 5
Notes to Consolidated Financial Statements............................................................ 6
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................. 16
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk............................................ 23
ITEM 4. Controls and Procedures............................................................................... 25
Forward-Looking Statements............................................................................ 25
PART II Other Information
ITEM 1. Legal Proceedings..................................................................................... 27
ITEM 4. Submission of Matters to a Vote of Security Holders................................................... 28
ITEM 5. Other Information..................................................................................... 28
ITEM 6. Exhibits and Reports on Form 8-K...................................................................... 28
SIGNATURE................................................................................................................. 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 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)
June 30, December 31,
2003 2002
----------- ------------
ASSETS:
Property and plant, net $ 6,094 $ 5,991
Investments and other assets:
Nuclear decommissioning trust fund 191 172
Other assets 240 235
----------- ------------
Total investments and other assets 431 407
----------- ------------
Current assets:
Cash and cash equivalents 21 9
Accounts receivable - trade (less allowance for doubtful
accounts of $5 and $6, respectively) 156 171
Unbilled revenue 164 101
Miscellaneous accounts and notes receivable 41 49
Materials and supplies, at average cost 163 162
Other current assets 21 26
----------- ------------
Total current assets 566 518
----------- ------------
Regulatory assets 746 659
----------- ------------
Total Assets $ 7,837 $ 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 1,484 1,477
Accumulated other comprehensive income (loss) (61) (58)
----------- ------------
Total common stockholder's equity 2,636 2,632
----------- ------------
Preferred stock not subject to mandatory redemption 113 113
Long-term debt, net 1,765 1,687
----------- ------------
Total capitalization 4,514 4,432
----------- ------------
Current liabilities:
Current maturities of long-term debt 141 130
Short-term debt 177 250
Intercompany notes payable 169 15
Accounts and wages payable 164 348
Taxes accrued 212 118
Other current liabilities 103 96
----------- ------------
Total current liabilities 966 957
----------- ------------
Accumulated deferred income taxes 1,290 1,344
Accumulated deferred investment tax credits 118 121
Regulatory liabilities 108 121
Asset retirement obligations 397 174
Accrued pension liabilities 268 252
Other deferred credits and liabilities 176 174
----------- ------------
Total Capital and Liabilities $ 7,837 $ 7,575
=========== ============
See Notes to Consolidated Financial Statements.
2
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF INCOME
(Unaudited, in millions)
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------- ---------------------------
2003 2002 2003 2002
------------- ------------- ------------ -------------
OPERATING REVENUES:
Electric $ 616 $ 654 $ 1,171 $ 1,188
Gas 20 18 85 68
------------- ------------- ------------ -------------
Total operating revenues 636 672 1,256 1,256
------------- ------------- ------------ -------------
OPERATING EXPENSES:
Fuel and purchased power 122 132 263 276
Gas 13 10 52 42
Other operations and maintenance 188 207 374 391
Depreciation and amortization 71 69 141 141
Income taxes 59 63 97 91
Other taxes 54 55 107 107
------------- ------------- ------------ -------------
Total operating expenses 507 536 1,034 1,048
------------- ------------- ------------ -------------
OPERATING INCOME 129 136 222 208
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction - 1 - 2
Miscellaneous, net -
Miscellaneous income 8 17 9 23
Miscellaneous expense (2) (29) (3) (31)
Income taxes (2) 9 (2) 8
------------- ------------- ------------ -------------
Total other income and (deductions) 4 (2) 4 2
------------- ------------- ------------ -------------
INTEREST CHARGES:
Interest 27 27 53 54
Allowance for borrowed funds used during construction (1) - (2) (2)
------------- ------------- ------------ -------------
Net interest charges 26 27 51 52
------------- ------------- ------------ -------------
NET INCOME 107 107 175 158
PREFERRED STOCK DIVIDENDS 2 2 3 4
------------- ------------- ------------ -------------
NET INCOME AFTER PREFERRED STOCK DIVIDENDS $ 105 $ 105 $ 172 $ 154
============= ============= ============ =============
See Notes to Consolidated Financial Statements.
3
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited, in millions)
Six Months Ended
June 30,
--------------------------
2003 2002
------------ ------------
Cash Flows From Operating:
Net income $ 175 $ 158
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 141 141
Amortization of nuclear fuel 16 16
Amortization of debt issuance costs and premium/discounts 2 2
Allowance for funds used during construction (2) (4)
Deferred income taxes, net (16) (9)
Deferred investment tax credits, net (3) (3)
Other (3) -
Changes in assets and liabilities:
Receivables, net (40) (63)
Materials and supplies (1) 8
Accounts and wages payable (147) (119)
Taxes accrued 94 82
Assets, other (14) (9)
Liabilities, other 36 43
------------ ------------
Net cash provided by operating activities 238 243
------------ ------------
Cash Flows From Investing:
Construction expenditures (226) (246)
Allowance for funds used during construction 2 4
Nuclear fuel expenditures (1) (16)
Intercompany notes receivable - 84
------------ ------------
Net cash used in investing activities (225) (174)
------------ ------------
Cash Flows From Financing:
Dividends on common stock (165) (152)
Dividends on preferred stock (3) (4)
Capital issuance costs (3) -
Redemptions:
Nuclear fuel lease (20) -
Short-term debt (73) (186)
Long-term debt (189) -
Issuances:
Nuclear fuel lease - 6
Long-term debt 298 -
Intercompany notes payable 154 260
------------ ------------
Net cash used in financing activities (1) (76)
------------ ------------
Net change in cash and cash equivalents 12 (7)
Cash and cash equivalents at beginning of year 9 15
------------ ------------
Cash and cash equivalents at end of period $ 21 $ 8
============ ============
Cash paid during the periods:
Interest $ 45 $ 48
Income taxes, net 74 63
See Notes to Consolidated Financial Statements.
4
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF COMMON STOCKHOLDER'S EQUITY
(Unaudited, in millions)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- --------------------------
2003 2002 2003 2002
------------ ------------- ------------ ------------
Common stock $ 511 $ 511 $ 511 $ 511
Other paid-in capital 702 702 702 702
Retained earnings
Beginning balance 1,462 1,413 1,477 1,440
Net income 107 107 175 158
Common stock dividends (83) (76) (165) (152)
Preferred stock dividends (2) (2) (3) (4)
------------ ------------- ------------ ------------
1,484 1,442 1,484 1,442
------------ ------------- ------------ ------------
Accumulated other comprehensive income (loss)
Beginning balance - derivative financial instruments 3 (1) 4 1
Change in derivative financial instruments in current period (2) 2 (3) -
------------ ------------- ------------ ------------
1 1 1 1
------------ ------------- ------------ ------------
Beginning balance - minimum pension liability (62) - (62) -
Change in minimum pension liability in current period - - - -
------------ ------------- ------------ ------------
(62) - (62) -
------------ ------------- ------------ ------------
(61) 1 (61) 1
------------ ------------- ------------ ------------
Total common stockholder's equity $ 2,636 $ 2,656 $ 2,636 $ 2,656
============ ============= ============ ============
Comprehensive income, net of taxes
Net income $ 107 $ 107 $ 175 $ 158
Unrealized net gain/(loss) on derivative hedging instruments,
net of income taxes of $(1), $1, $(1) and $1, respectively (2) 1 (2) 2
Reclassification adjustments for gains/(losses) included in net income,
net of income taxes of $-, $-, $- and $(1), respectively - 1 (1) (2)
------------ ------------- ------------ ------------
Total comprehensive income, net of taxes $ 105 $ 109 $ 172 $ 158
============ ============= ============ ============
See Notes to Consolidated Financial Statements.
5
UNION ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
June 30, 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 primarily 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 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 AmerenEnergy 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 effective January 1, 2003. SFAS 143
provides the accounting requirements for asset retirement obligations associated
with tangible long-lived assets. SFAS 143 requires us to record the estimated
fair value of legal obligations associated with the retirement of tangible
long-lived assets in the period in which the liabilities are incurred and to
capitalize a corresponding amount as part of the book value of the related
long-lived asset. In subsequent periods, we are required to adjust asset
retirement obligations based on changes in estimated fair value. Corresponding
increases in asset book values are depreciated over the remaining useful life of
the related asset. Uncertainties as to the probability, timing or amount of cash
flows associated with an asset retirement obligation affect our estimate of fair
value.
Upon adoption of this standard, we recognized additional asset retirement
obligations of approximately $213 million and a net increase in net property and
plant of approximately $77 million related primarily to the Callaway nuclear
plant 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 that we had recorded at
January 1, 2003, related to our future obligations and funds accumulated to
decommission the Callaway nuclear plant.
Asset retirement obligations also increased by $4 million during the
quarter ended March 31, 2003 and $6 million during the quarter ended June 30,
2003 to reflect the obligations at their present value.
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.
The fair value of our nuclear decommissioning trust fund for our Callaway
nuclear plant is reported in Nuclear Decommissioning Trust Fund in our
Consolidated Balance Sheet. This amount is legally restricted for funding the
costs of nuclear decommissioning. Changes in the fair value of the trust fund
are recorded as an increase or decrease to the regulatory asset recorded in
connection with the adoption of SFAS 143.
Historically, our depreciation methodology has 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 depreciation 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 $542 million at June 30, 2003.
The following table shows the asset retirement obligation liability as
though SFAS 143 had been in effect for the two prior years.
====================================================
Pro forma Asset Retirement Obligation Liability
- ----------------------------------------------------
January 1, 2001 $ 346
December 31, 2001 366
December 31, 2002 387
====================================================
There are no pro forma net income effects of adopting SFAS 143 since we
expect to continue to recover in electric rates the cost of Callaway nuclear
decommissioning and other costs of removal.
7
Emerging Issues Task Force (EITF) Issue No. 02-3 and EITF Issue No. 98-10
In the quarters ended September 30, 2002 and December 31, 2002, we adopted
the provisions of EITF 02-3, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities," that require revenues and costs associated with
certain energy contracts to be shown on a net basis in the income statement.
Prior to adopting EITF 02-3 and the rescission of EITF 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities," our
accounting practice was to present all settled energy purchase or sale contracts
within our power risk management program on a gross basis in Operating Revenues
- - Electric and in Operating Expenses - Fuel and Purchased Power. This meant that
revenues were recorded for the sum of the contract notional amounts of the power
sales contracts with a corresponding charge to income for the costs of the
energy that was generated, or for the sum of the contract notional amounts of a
purchased power contract.
In October 2002, the EITF reached a consensus to rescind EITF 98-10. The
effective date for the full rescission of EITF 98-10 was for fiscal periods
beginning after December 15, 2002, with early adoption permitted. In addition,
the EITF reached a consensus in October 2002 that all SFAS No. 133 ("Accounting
for Derivative Instruments and Hedging Activities") trading derivatives
(subsequent to the rescission of EITF 98-10) should be shown net in the income
statement, whether or not physically settled. This consensus applies to all
energy and non-energy related trading derivatives that meet the definition of a
derivative pursuant to SFAS 133. The operating revenues and costs that were
netted for the three and six months ended June 30, 2002 were $78 million and
$228 million, respectively, which reduced Electric Revenues and Fuel and
Purchased Power by equal amounts. The adoption of EITF 02-3, the rescission of
EITF 98-10 and the related transition guidance resulted in netting of energy
contracts and lowered our reported revenues and costs with no impact on
earnings.
SFAS No. 149 - "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities"
In April 2003, the FASB issued SFAS 149. SFAS 149 clarifies under what
circumstances a contract with initial net investment meets the 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. We do not
expect SFAS 149 to have any impact on our financial position, results of
operations or liquidity in the third quarter of 2003.
SFAS No. 150 - "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150 that established standards for how an
issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. SFAS 150 requires financial
instruments that were issued in the form of shares with an unconditional
obligation, where the issuer must redeem the instrument by transferring its
assets on a specified date, be classified as liabilities. Accordingly, SFAS 150
requires issuers to classify mandatorily redeemable financial instruments as
liabilities. SFAS 150 also requires such financial instruments to be measured at
fair value and a cumulative effect adjustment to be recognized in the statement
of income for any difference between the carrying amount and fair value.
SFAS 150 will be effective in the third quarter of 2003. We do not expect
SFAS 150 to have any impact on our financial position, results of operations or
liquidity upon adoption in the third quarter of 2003.
FASB Interpretation No. (FIN) 46 - "Consolidation of Variable Interest Entities,
an Interpretation of Accounting Research Bulletin (ARB) No. 51, Consolidated
Financial Statements"
The FASB issued FIN 46 in January 2003. FIN 46 provides guidance on the
identification of, and financial reporting for, entities over which control is
achieved through means other than voting rights; such entities are known as
variable-interest entities (VIEs). FIN 46 will determine the following:
o Whether consolidation is required under the "controlling financial
interest" model of ARB 51, or other existing authoritative guidance;
o Or, alternatively, whether the variable-interest model under FIN 46
should be used to account for existing and new entities.
8
The initial application of FIN 46 depends on the date that the VIE was
created. For public entities, FIN 46 is effective no later than the beginning of
the first interim period that starts after June 15, 2003. At this time, we are
assessing the impact of FIN 46 on our financial position, results of operations,
or liquidity upon adoption in the third quarter of 2003.
Interchange Revenues
Interchange revenues included in Operating Revenues - Electric were $65
million for the three months ended June 30, 2003 (2002 - $62 million) and $167
million for the six months ended June 30, 2003 (2002 - $140 million).
Purchased Power
Purchased power included in Operating Expenses - Fuel and Purchased Power
was $36 million for the three months ended June 30, 2003 (2002 - $53 million)
and $81 million for the six months ended June 30, 2003 (2002 - $118 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 June 30, 2003 were $24 million (2002 - $28 million) and $47 million for
the six months ended June 30, 2003 (2002 - $49 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.
Pensions
At December 31, 2002, Ameren recorded a minimum accumulated pension
liability of $102 million, after taxes, which resulted in a charge to
Accumulated Other Comprehensive Income (Loss) (OCI) and a reduction in
stockholder's equity. Our share of the minimum pension liability was
approximately $62 million, after taxes. Based on changes in interest rates,
Ameren may need to change its actuarial assumptions for its pension plan at
December 31, 2003, which could result in a requirement to record an additional
minimum pension liability.
NOTE 2 - Rate and Regulatory Matters
Intercompany Purchase of Electric Generating Facilities and Sale of Illinois
Service Territory
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 by us, at net book value, of approximately 550 megawatts
(approximately $260 million) of combustion turbine generating units at
Pinckneyville and Kinmundy, Illinois from Generating Company. The purchase is
subject to receipt of necessary regulatory approvals and would be funded with
available liquidity and borrowings. 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.
In February 2003, we sought approval from the Federal Energy Regulatory
Commission (FERC) and the Illinois Commerce Commission (ICC) to purchase the 550
megawatts of generating assets from Generating Company. Several independent
power producers have objected to our request to 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 in
the ICC proceeding contending that NRG's 640 megawatt generating facility at
Vandalia, Missouri, known as the Audrain Facility, was a better resource for us
to acquire as compared to the Kinmundy and Pinckneyville combustion turbine
generating units. In addition, the ICC Staff filed testimony that expressed
concerns about whether the
9
purchase is the least cost generating resource for us, and recommended that the
ICC deny approval of the purchase.
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. On June
4, 2003, we filed a Motion for Reconsideration of this order contending that the
FERC erred in setting this matter for hearing. On June 10, 2003, we filed direct
testimony with the FERC in support of the proposed purchase. On August 8, 2003,
two intervenors, NRG and The Electric Power Supply Association, filed testimony
opposing the proposed purchase.
On May 30, 2003, we filed a Notice of Withdrawal with the ICC stating that
we elected not to pursue approval of the purchase and were withdrawing our
request. In the Notice, we stated that the concerns expressed by the ICC Staff
regarding our means of satisfying our generating capacity needs, as well as the
MoPSC's views of the appropriate means of meeting generating capacity
obligations, have demonstrated to us the difficulty of a single company
operating as an electric utility in both a regulated generation jurisdiction
such as Missouri and an unregulated generation jurisdiction such as Illinois. To
remedy this difficulty, we announced in the Notice our plan to limit our public
utility operations to the State of Missouri and to discontinue operating as a
public utility subject to ICC regulation. We intend to accomplish this plan by
selling our Illinois-based electric and natural gas businesses, including our
Illinois-based distribution assets and certain of our transmission assets, to
AmerenCIPS. Our electric generating facilities and certain of our electric
transmission facilities in Illinois would not be part of the sale. We propose to
sell the assets at their net book value. In 2002, our Illinois service territory
generated revenues of $166 million and is estimated to have a net book value of
$138 million at December 31, 2003. The sale of our Illinois-based utility
businesses will require the approval of the ICC, the FERC, the MoPSC and the SEC
under the provisions of the PUHCA. On June 13, 2003, the ICC Staff filed a
response to our Notice of Withdrawal indicating that the ICC Staff did not
object to it and on July 23, 2003, the ICC issued an order accepting the
withdrawal. In the third quarter of 2003, we expect to file with the MoPSC, the
ICC, the FERC and the SEC for authority to sell our Illinois-based utility
businesses to AmerenCIPS. We propose to transfer approximately one-half of the
assets directly to AmerenCIPS in consideration for an AmerenCIPS promissory
note, and approximately one-half of the assets by means of a dividend in kind to
Ameren followed by a capital contribution by Ameren to AmerenCIPS.
Upon receipt of these regulatory approvals and completion of the sale of
our Illinois-based utility businesses, the ICC's approval will no longer be
required for the purchase of the Pinckneyville and Kinmundy combustion turbine
generating units by us from Generating Company. We intend to continue with the
intercompany purchase of these electric generating facilities and will continue
to seek approvals from regulators having jurisdiction over the transaction. FERC
approval of the transaction is needed, and because the transaction does not
require state regulatory approval, SEC approval under the PUHCA is also
required.
We are unable to predict the ultimate outcome of these regulatory
proceedings or the timing of the final decisions of the various agencies. The
timing of regulatory approvals of these proposed transactions is not anticipated
to have any material effect on our financial position, results of operations or
liquidity.
Regional Transmission Organization (RTO)
Since April 2002, we, 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.
10
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. At this time, the parties are pursuing
settlement of the disputed rate issues. Absent settlement, the rates filed in
the February 28 filing will go into effect on October 1, 2003, subject to
refund. On May 15, 2003, the FERC issued an order accepting the February 18,
2003 compliance filing.
Once GridAmerica becomes operational and Ameren has secured approval to
participate in GridAmerica from the MoPSC, the FERC has ordered the return of
the $18 million exit fee, with interest, paid by Ameren when it previously left
the Midwest ISO. Our share of the exit fee to be returned is $13 million. Until
the tariffs and other material terms of our and AmerenCIPS' participation in
GridAmerica, and GridAmerica's participation in the Midwest ISO, are finalized
and approved by the FERC, we are unable to predict the ultimate impact that
on-going regional transmission organization developments will have on our
financial position, results of operations or liquidity. Our participation in
GridAmerica is also subject to MoPSC approval. We expect GridAmerica to become
operational by later in 2003, subject to regulatory approvals.
In July 2003, the FERC issued an Order (July Order) that could potentially
reduce our, as well as other utilities', "through and out" transmission revenues
effective November 1, 2003, reversing an Administrative Law Judge's previous
decision on this matter. The revenues subject to elimination by the July Order
are those revenues from transmission reservations that travel through or out of
our transmission system and are also used to provide electricity to load within
the Midwest ISO or PJM Interconnection LLC systems. The magnitude of the
potential net revenue reduction resulting from the July Order is still being
evaluated, but could be up to $20 to $25 million annually for Ameren. While it
is anticipated that Ameren's transmission revenues could be reduced by the July
Order, transmission expenses for our affiliates could also be reduced. Our
portion of the potential net revenue reduction could be up to $14 to $17 million
annually. Moreover, the FERC's Order explicitly permits companies participating
in an RTO to seek collection of the lost "through and out" revenues through
other rate mechanisms. At this time, we intend to seek rehearing of the July
Order. We also intend to seek recovery of any potential lost "through and out"
revenues through rate mechanisms acknowledged by the FERC in the July Order.
Standard Market Design Notice of Proposed Rulemaking (NOPR)
On July 31, 2002, the FERC issued a Standard Market Design NOPR. The NOPR
proposes a number of changes to the way the current wholesale transmission
service and energy markets are operated. Specifically, the NOPR calls for all
jurisdictional transmission facilities to be placed under the control of an
independent transmission provider (similar to an RTO), proposes a new
transmission service tariff that provides a single form of transmission service
for all users of the transmission system including bundled retail load, and
proposes a new energy market and congestion management system that uses
locational marginal pricing as its basis.
Although issuance of the final rule is uncertain and its implementation
schedule is unknown, the Midwest ISO is already in the process of implementing a
separate market design similar to the proposed market design in the NOPR. In
July 2003, the Midwest ISO filed with the FERC a revised OATT codifying the
terms and conditions under which it will implement the new market design. The
Midwest ISO has targeted March 2004 as the start date for implementation. We are
reviewing the Midwest ISO's market design and the potential impact of the market
design on the cost and reliability of service to retail customers. At this time,
we are unable to predict the ultimate impact the new market design will have on
our future financial position, results of operations or liquidity.
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 Staff has
recommended an annual increase of approximately $2 million and other parties
have also proposed a lower increase. Hearings were completed in June and July
2003. The ICC has until October 2003 to render a decision in this gas case and
any rate change is expected to be effective in November 2003.
11
Missouri Gas
In May 2003, we filed a request with the MoPSC to increase annual rates for
natural gas service by approximately $27 million. We proposed to phase in the
rate increases over two years, with one half of the increase taking effect
December 1, 2003 and the other half taking effect November 1, 2004. We also
proposed not to seek additional increases in gas rates through November 1, 2006
subject to certain exceptions. Our proposal also called for us to contribute
$1.75 million to an energy assistance program to help low-income customers. The
direct testimony of the MoPSC Staff and other parties to this proceeding is due
to be filed with the MoPSC in October 2003. A pre-hearing settlement conference
is scheduled to be held in October 2003 and a hearing is scheduled to be held in
January 2004. The MoPSC has until April 2004 to render a decision in this gas
case.
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 $24 million for the three months ended June 30, 2003 (2002 - $23
million) and $51 million for the six months ended June 30, 2003 (2002 - $50
million). Intercompany power sales totaled $25 million for the three months
ended June 30, 2003 (2002 - $17 million) and $57 million for the six months
ended June 30, 2003 (2002 - $37 million).
Interchange revenues from outside sales of available generation through
AmerenEnergy were $41 million for the three months ended June 30, 2003 (2002 -
$41 million) and $111 million for the six months ended June 30, 2003 (2002 - $95
million). Purchased power derived from AmerenEnergy was $11 million for the
three months ended June 30, 2003 (2002 - $30 million) and $28 million for the
six months ended June 30, 2003 (2002 - $67 million).
Costs of support services provided by Ameren Services and AmerenEnergy,
including wages, employee benefits and professional services are based on actual
costs incurred. Support services included in Operating Expenses - Other
Operations and Maintenance for the three months ended June 30, 2003 totaled $47
million (2002 - $48 million) and $97 million for the six months ended June 30,
2003 (2002 - $96 million).
As of June 30, 2003, intercompany receivables included in Miscellaneous
Accounts and Notes Receivable were approximately $14 million (December 31, 2002
- - $25 million). As of June 30, 2003, intercompany payables included in Accounts
and Wages Payable totaled approximately $55 million (December 31, 2002 - $103
million).
We have the ability to borrow from Ameren Corporation 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 June 30, 2003 was
our commercial paper program. Through the utility money pool we can access
committed credit facilities at Ameren Corporation and AmerenCIPS, which totaled
$615 million at June 30, 2003. These facilities are in addition to our own $157
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 Corporation, AmerenCIPS or
Ameren Services have surplus funds and the availability of other external
borrowing sources. 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 June 30, 2003, the average
interest rate for the utility money pool was 1.19% (2002 - 1.75%) and for the
six months ended June 30, 2003 was 1.25% (2002 - 1.77%). At June 30, 2003, we
had outstanding intercompany notes payables of $167 million, sourced by internal
funds through the utility money pool (December 31, 2002 - $15 million). Subject
to the receipt of regulatory approval, which is being pursued, AmerenCILCO will
also participate in the utility money pool arrangement.
12
We jointly dispatch generation with Generating Company under an amended
joint dispatch agreement. Under the amended agreement, both of us are entitled
to serve our load requirements from our own least-cost generation first, and
then allow the other company access to any available excess generation. The
agreement has no expiration, but either party may give a one year notice of
termination beginning January 1, 2004. Termination of this agreement could have
a material adverse impact on our business.
NOTE 4 - Derivative Financial Instruments
As of June 30, 2003, we recorded the fair value of derivative financial
instrument assets of $7 million in Other Assets and the fair value of derivative
financial instrument liabilities of $4 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
OCI due to transactions going to delivery or settlement, was a $0.2 million gain
for the three months (2002 - $1 million loss) and a $0.5 million loss for the
six months ended June 30, 2003. For the six months ended June 30, 2002, the
second quarter loss on power forward derivative instruments offset the $1
million gain from the first quarter.
As of June 30, 2003, we had hedged a portion of the electricity price
exposure for periods generally less than one year. The mark-to-market value
accumulated in OCI for the effective portion of hedges of electricity price
exposure was a net gain of approximately $0.7 million ($0.4 million, net of
taxes).
As of June 30, 2003, a loss of approximately $1 million (less than $1
million, net of taxes) associated with natural gas swaps was included in OCI.
The swaps are a partial hedge of our natural gas requirements through October
2006.
We also hold two call options for coal with two suppliers. These options to
purchase coal expire October 2003 and July 2005. As of June 30, 2003, a
mark-to-market gain of approximately $5 million ($3 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. Certain of these transactions are treated as
non-hedge transactions under SFAS 133. The net 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 $0.4 million ($0.2 million, net of taxes) for the three months ended
June 30, 2003 and $0.4 million ($0.2 million, net of taxes) for the six months
ended June 30, 2003. For the three and six months ended June 30, 2002, the above
related amounts were a $2 million gain ($1 million, net of taxes) and a $3
million gain ($2 million, net of taxes).
NOTE 5 - Property and Plant, Net
Property and plant, net at June 30, 2003 and December 31, 2002 consisted of
the following:
================================================================================
June 30, December 31,
2003 2002
- --------------------------------------------------------------------------------
Property and plant, at original cost:
Electric $10,575 $10,294
Gas 272 268
Other 37 36
- --------------------------------------------------------------------------------
10,884 10,598
Less accumulated depreciation and amortization 5,134 4,968
- --------------------------------------------------------------------------------
5,750 5,630
13
Construction work in progress:
Nuclear fuel in process 71 81
Other 273 280
- --------------------------------------------------------------------------------
Property and plant, net $ 6,094 $ 5,991
================================================================================
NOTE 6 - Debt Financings
In August 2002, the SEC declared effective a shelf registration statement
filed by us covering 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 matured
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 debt.
In July 2003, we issued, pursuant to the shelf registration, $200 million
of 5.10% Senior Secured Notes due August 1, 2018. We received net proceeds after
fees of $198 million, which, along with other funds, were used to repay
short-term debt incurred to fund the maturity of $100 million principal amount
7.65% first mortgage bonds due July 15, 2003 and to repay $21 million of other
short-term debt. The remaining proceeds will be used to redeem and refinance,
prior to maturity, $75 million principal amount of outstanding 7.15% first
mortgage bonds due August 1, 2023 at a redemption price of 103.01% of par, plus
accrued interest in August 2003.
In August 2003, we plan to file another shelf registration statement with
the SEC. We expect this registration statement, when declared effective by the
SEC, will authorize the offering from time to time of up to $1 billion of
various forms of long-term debt and trust preferred securities to refinance
existing debt and for general corporate purposes, including the repayment of
short-term debt incurred to finance construction expenditures and other working
capital needs. The $79 million remaining authorization under the August 2002
shelf registration statement is expected to be included in the $1 billion of
securities proposed to be issued under this registration statement.
Once declared effective by the SEC, we may sell all, or a portion of, the
securities registered 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.
In April 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. AmerenCIPS can access this facility through the utility money pool.
In July 2003, Ameren Corporation entered into two new credit agreements for
$470 million in revolving credit facilities to be used for general corporate
purposes, including support of our commercial paper program through the utility
money pool. The $470 million in new facilities includes a $235 million 364-day
revolving credit facility and a $235 million three-year revolving credit
facility. These new credit facilities replaced Ameren Corporation's existing
$270 million 364-day revolving credit facility, which matured in July 2003, and
a $200 million facility, which would have matured in December 2003. The new
credit facilities contain provisions which require Ameren to meet minimum
Employee Retirement Income Security Act (ERISA) funding requirements for its
pension plan. The prior credit facilities included more
14
restrictive provisions related to the funded status of Ameren's pension plan,
which are not present in the new facilities. In addition, in July 2003, Ameren
Corporation entered into an amendment of an existing $130 million multi-year
credit facility that similarly modified the ERISA-related provisions in this
facility. As a result, all of Ameren Corporation's facilities require it to meet
minimum ERISA funding requirements, but do not otherwise limit the underfunded
status of its pension plan. At July 31, 2003, all of such borrowing capacity
under these facilities was available to Ameren and its subsidiaries.
At June 30, 2003, neither Ameren, nor any of its subsidiaries, including
us, had any off-balance sheet financing arrangements, other than operating
leases entered into in the ordinary course of business.
Amortization of debt issuance costs and any premium or discounts for the
three and six months ended June 30, 2003 of $1 million (2002 - $1 million) and
$2 million (2002 - $2 million), respectively, were included in interest expense
in the income statement.
At June 30, 2003, Ameren Corporation and its subsidiaries, including us,
were in compliance with their financial agreement provisions and covenants.
NOTE 7 - Miscellaneous, Net
Miscellaneous, net for the three and six months ended June 30, 2003 and
2002 consisted of the following:
============================================================================================================
Three Months Six Months
- ------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
Miscellaneous income:
Interest and dividend income $ - $ 2 $ - $ 2
Equity in earnings of subsidiary 4 10 5 11
Gain on disposition of property and other assets - 5 - 8
Other 4 - 4 2
- -------------------------------------------------------------------------------------------------------------
Total miscellaneous income $ 8 $ 17 $ 9 $ 23
- -------------------------------------------------------------------------------------------------------------
Miscellaneous expense:
Plant acquisition amortization $ - $ - $ - $ (1)
Loss on disposition of property and other assets - (1) - -
Donations - rate case settlement - (26) - (26)
Other (2) (2) (3) (4)
- -------------------------------------------------------------------------------------------------------------
Total miscellaneous expense $ (2) $(29) $ (3) $(31)
- -------------------------------------------------------------------------------------------------------------
15
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 Acquisitions 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 primarily 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 and renamed it
AmerenEnergy Medina Valley Cogen (No. 4), LLC. See Acquisitions for further
information.
o AmerenEnergy, Inc. (AmerenEnergy), which serves as a power marketing and
risk management agent for 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 The financial statements and related notes included in our Quarterly Report
on Form 10-Q for the period ended March 31, 2003.
o Management's Discussion and Analysis of Financial Condition and Results of
Operations that appears in our Annual Report on Form 10-K for the period
ended December 31, 2002, as amended by Form 10-K/A.
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, as
amended by Form 10-K/A.
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 AmerenEnergy Fuels and Services Company. All
tabular dollar amounts are in millions, unless otherwise indicated.
Our results of operations and financial position are affected by many
factors. Weather, economic conditions and the actions of key customers or
competitors can significantly impact the demand for our services. Our results
are also affected 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,
16
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 Missouri and Illinois are largely
set through 2006. Fluctuations in interest rates impact our cost of borrowings,
and pension and post-retirement benefits. We employ various risk management
strategies in order to try to reduce our exposure to commodity risks and other
risks inherent in our business. The reliability of our power plants, and
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.
Acquisitions
On January 31, 2003, Ameren completed its acquisition of all of the
outstanding common stock of CILCORP from The AES Corporation. CILCORP is the
parent company of Peoria, Illinois-based Central Illinois Light Company, which
operated as CILCO. With the acquisition, CILCO became an indirect Ameren
subsidiary, but remains a separate utility company, operating as AmerenCILCO. On
February 4, 2003, Ameren also completed its acquisition of AES Medina Valley
Cogen (No. 4), LLC (Medina Valley), which indirectly owns a 40 megawatt,
gas-fired electric generation plant. With the acquisition, Medina Valley, which
was renamed AmerenEnergy Medina Valley Cogen (No. 4), LLC, became a wholly-owned
subsidiary of Resources Company. The results of operations for CILCORP and
AmerenEnergy Medina Valley Cogen (No. 4), LLC were included in Ameren's
consolidated financial statements effective with the January and February 2003
acquisition dates. Our results of operations for the three and six months ended
June 30, 2003 were not impacted by these acquisitions.
Ameren acquired CILCORP to complement its existing Illinois gas and
electric operations. The purchase included CILCO's rate-regulated electric and
natural gas businesses in Illinois serving approximately 200,000 and 205,000
customers, respectively, of which approximately 150,000 are combination electric
and gas customers. CILCO's service territory is contiguous to our service
territory. CILCO also has a non rate-regulated electric and gas marketing
business principally focused in the Chicago, Illinois region. Finally, the
purchase included approximately 1,200 megawatts of largely coal-fired generating
capacity, most of which is expected to become non rate-regulated in 2003.
The total acquisition cost was approximately $1.4 billion and included the
assumption of CILCORP and Medina Valley debt and preferred stock at closing of
$895 million and consideration of $489 million in cash, net of cash acquired.
The cash component of the purchase price came from Ameren's issuances in
September 2002 of 8.05 million common shares and its issuance in early 2003 of
an additional 6.325 million common shares, which together generated aggregate
net proceeds of $575 million.
RESULTS OF OPERATIONS
Earnings Summary
Our net income of $107 million in the second quarter of 2003 was comparable
to the second quarter of 2002. Second quarter earnings were negatively impacted
by milder weather. The impact of the mild weather, however, was offset by lower
operations and maintenance expenses, favorable interchange margins due to
improved power prices in the energy markets and solid low-cost generation
available for sale. In addition, we expensed costs of economic development and
energy assistance programs that were required by a Missouri electric rate case
settlement in the second quarter of 2002.
Our net income increased $17 million to $175 million for the six months
ended June 30, 2003 compared to the year-ago earnings of $158 million. In
addition to the items discussed above, net income for the first six months of
2003 benefited from higher interchange margins and colder winter weather than in
2002, which resulted in increased native load electric demand and higher gas
margins in the first quarter of 2003.
17
Electric Operations
The following table represents the favorable (unfavorable) variation on
electric margins for the three and six months ended June 30, 2003 from the
comparable period in 2002:
================================================================================
Three Months Six Months
- --------------------------------------------------------------------------------
Electric Revenues:
Interchange revenues $ 3 $ 27
Effect of weather (estimate) (49) (28)
Rate reductions (5) (16)
Growth and other (estimate) 13 -
- --------------------------------------------------------------------------------
Total variation in electric operating revenues (38) (17)
- --------------------------------------------------------------------------------
Fuel and Purchased Power:
Fuel:
Generation $ (5) $ (21)
Price (3) (3)
Generation efficiencies and other 1 -
Purchased power 17 37
- --------------------------------------------------------------------------------
Total variation in fuel and purchased power 10 13
- --------------------------------------------------------------------------------
Change in electric margin $ (28) $ (4)
================================================================================
Electric margin decreased $28 million for the three months and $4 million
for the six months ended June 30, 2003 compared to the same periods in 2002.
Decreases in electric margin in the second quarter and first six months of 2003
were primarily attributable to unfavorable weather conditions and rate
reductions resulting from the 2002 Missouri electric rate case settlement,
partially offset by increased interchange margins. The unfavorable weather
conditions were primarily due to mild early summer weather in the second quarter
of 2003 versus warmer than normal conditions in the same period in 2002. In our
service territory, weather-sensitive residential and commercial electric
kilowatthour sales declined 17% and 10%, respectively, in the second quarter of
2003 (year-to-date - 1% and 2%, respectively) compared to 2002. Cooling degree
days were approximately 30% and 40% less in the second quarter of 2003 compared
to normal and the prior year period, respectively.
Rate reductions of $50 million and $30 million effective April 1, 2002 and
2003, respectively, relating to the 2002 rate case settlement in Missouri, also
negatively impacted electric revenues in the first six months of 2003. Revenues
will be further negatively affected by the settlement of the Missouri electric
rate case, due to an additional $30 million of annual electric rate reduction
effective April 1, 2004.
Interchange margins increased approximately $11 million in the second
quarter and approximately $40 million in the first six months of 2003 due to
improved power prices in the energy markets and solid low-cost generation
availability. Average power prices increased to approximately $36 per
megawatthour in the first six months of 2003 from approximately $24 per
megawatthour in the first six months of 2002. Fuel and purchased power decreased
$10 million in the second quarter and $13 million in the first six months of
2003 due to greater availability of low-cost generation.
The growth and other line item includes our sale of emission credits. The
sale of emission credits increased in the second quarter of 2003 by $4 million,
but decreased in the first six months of 2003 by $9 million, compared to the
same periods in 2002. In addition, industrial electric kilowatthour sales
increased approximately 14% in the second quarter of 2003 in our service
territory.
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 and six months ended June 30, 2002
were $78 million and $228 million, respectively, which reduced interchange
revenues and purchased power 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.
18
Gas Operations
Our gas margin decreased $1 million in the second quarter of 2003, compared
to the second quarter of 2002, as a result of more mild weather. Our gas margin
increased $7 million in the first six months of 2003, compared to the same
period in the prior year, primarily due to increased customer demand resulting
from colder winter weather in the first quarter of 2003.
Other Operating Expenses
Other Operations and Maintenance
Other operations and maintenance expenses decreased $19 million in the
second quarter and $17 million in the first six months of 2003, compared to the
prior year periods, primarily due to lower labor costs related to our voluntary
employee retirement program instituted at the end of 2002 and lower maintenance
costs at our power plants primarily due to the number and timing of outages. The
decreases in expense were partially offset by higher employee benefit costs,
primarily related to higher healthcare and pension costs.
Costs of support services provided by Ameren Services and AmerenEnergy,
including wages, employee benefits and professional services are based on actual
costs incurred. 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 increased $2 million in the second
quarter of 2003, compared to the year-ago period, as a result of capital
additions in 2002. For the six months ended June 30, 2003, increases in
depreciation and amortization expenses as a result of capital additions were
offset by a $5 million reduction in depreciation expense in the first quarter of
2003 resulting from a $20 million annual depreciation reduction of depreciation
rates. This reduction was based on the updated analysis of asset values, service
lives and accumulated depreciation levels that were required by our 2002
Missouri electric rate case settlement.
Income Taxes
Income tax expense increased $7 million in the second quarter of 2003, as
compared to the second quarter of 2002, primarily due to a higher effective tax
rate. Income tax expense increased $16 million in the first six months of 2003,
as compared to the same period in 2002, primarily due to higher pretax income.
Other Taxes
Other taxes expense decreased $1 million in the second quarter or 2003,
compared to the second quarter of 2002, primarily due to a decrease in gross
receipts taxes related to lower native sales as a result of milder weather.
Other tax expense for the six months ended 2003 was comparable to the prior year
period.
Other Income and Deductions
Other income and deductions (excluding income taxes) increased $17 million
in the second quarter of 2003 and $12 million in the first six months of 2003,
compared to the same periods in the prior year, primarily due to expensing in
2002 of economic development and energy assistance programs required in the
Missouri electric rate case settlement ($26 million), partially offset by a
decrease in earnings from our ownership interest in EEI and decreased gains on
derivative contracts.
Interest
Interest expense in the second quarter of 2003 was comparable to the prior
year period. Interest expense in the first six months of 2003 decreased $1
million, compared to the 2002 period, primarily due to lower interest rates on
new issuances of first mortgage bonds as compared to those redeemed.
19
LIQUIDITY AND CAPITAL RESOURCES
Operating
Our cash flows provided by operating activities were $238 million for the
first six months of 2003, compared to $243 million for the same period in 2002.
Cash provided by operating activities decreased slightly in the first six months
of 2003 primarily as a result of increased electric and gas operating margins,
offset by increased working capital requirements.
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 $225 million in the first six
months of 2003, compared to $174 million for the same period in 2002. The
increase over the prior year period was primarily related to the 2002 receipt of
$84 million we had invested in the utility money pool, partially offset by lower
construction and nuclear fuel expenditures in 2003. In the first six months of
2003, construction expenditures were $226 million (2002 - $246 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 be added to or
removed from our portfolio, the type of generation asset technology that will be
employed, or whether capacity may be purchased, among other things. Any changes
that we may plan to make for future generating needs could result in significant
capital expenditures or losses being incurred, which could be material.
Financing
Our cash flows used in financing activities totaled $1 million in the first
six months of 2003 and $76 million for the comparable period in 2002. Our
principal financing activities for the first six months of 2003 included the
redemptions of short-term and long-term debt, as well as payments of dividends,
partially offset by issuances of long-term debt and intercompany notes payable.
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 and intercompany borrowings
through Ameren's utility money pool (maturities generally within 1 to 45 days).
At June 30, 2003, Ameren Corporation and its subsidiaries had committed credit
facilities, expiring at various dates through 2005, totaling $772 million,
excluding AmerenCILCO facilities of $59 million, EEI facilities of $41 million
and our nuclear fuel lease facilities of $120 million. This amount includes $157
million of our committed credit facilities and $615 million of committed credit
facilities at Ameren Corporation and AmerenCIPS. We access these combined
facilities through Ameren's utility money pool arrangement. AmerenCIPS and
Ameren Services may also borrow under this arrangement. Subject to the receipt
of regulatory approval, which is being pursued, AmerenCILCO will also
participate in the utility money pool arrangement. These committed credit
facilities are used to support our commercial paper program, under which $177
million was outstanding at June 30, 2003. At June 30, 2003, $595 million was
unused and available under these committed credit facilities.
In July 2003, Ameren Corporation entered into two new credit agreements for
$470 million in revolving credit facilities to be used for general corporate
purposes, including the support of our commercial paper program through the
utility money pool. The $470 million in new facilities includes a $235 million
364-day revolving credit facility and a $235 million three-year revolving credit
facility. These new credit facilities replaced Ameren Corporation's existing
$270 million 364-day revolving credit
20
facility, which matured in July 2003, and a $200 million facility, which would
have matured in December 2003. The new credit facilities contain provisions
which require Ameren to meet minimum Employee Retirement Income Security Act
(ERISA) funding requirements for its pension plan. The prior credit facilities
included more restrictive provisions related to the funded status of Ameren's
pension plan, which are not present in the new facilities. In addition, in July
2003, Ameren Corporation entered into an amendment of an existing $130 million
multi-year credit facility that similarly modified the ERISA-related provisions
in this facility. As a result, all of Ameren Corporation's facilities require it
to meet minimum ERISA funding requirements, but do not otherwise limit the
underfunded status of its pension plan. At July 31, 2003, all of such borrowing
capacity under these facilities was available to Ameren and its subsidiaries.
EEI also has two bank credit agreements totaling $41 million that expire in
2004. At June 30, 2003, $41 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 June 30, 2003, the maximum amount that could be financed under the
agreement was $120 million. At June 30, 2003, $93 million was financed under the
lease.
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. Our inability to raise capital on favorable terms,
particularly during times of uncertainty in the capital markets, could
negatively impact our ability to maintain and grow our businesses. Based on our
current credit ratings, we believe that we will continue to have access to the
capital markets. However, events beyond our control may create uncertainty in
the capital markets such that our cost of capital would increase or our ability
to access the capital markets would be adversely affected.
Financial Agreement Provisions and Covenants
Our financial agreements and those of Ameren include customary default or
cross default provisions that could impact the continued availability of credit
or result in the acceleration of repayment. The majority of the committed credit
facilities of Ameren and its subsidiaries each require the borrower to
represent, in connection with any borrowing under the facility, that no material
adverse change has occurred since certain dates. None of our financing
arrangements, nor those of Ameren and its other subsidiaries, contain credit
rating triggers, except for three funded bank term loans at AmerenCILCO totaling
$105 million at June 30, 2003.
At June 30, 2003, Ameren Corporation and its subsidiaries, including us,
were in compliance with their financial agreement provisions and covenants.
Debt Issuances and Redemptions
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
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 matured 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 debt.
In July 2003, we issued, pursuant to the shelf registration, $200 million
of 5.10% Senior Secured Notes due August 1, 2018. We received net proceeds after
fees of $198 million, which, along with other funds, were used to repay
short-term debt incurred to fund the maturity of $100 million principal amount
7.65% first mortgage bonds due July 15, 2003 and to repay $21 million of other
short-term debt. The remaining proceeds will be used to redeem and refinance,
prior to maturity, $75 million principal amount of outstanding 7.15% first
mortgage bonds due August 1, 2023 at a redemption price of 103.01% of par, plus
accrued interest in August 2003.
21
See also Note 6 - Debt Financings to our Consolidated Financial Statements
under Item 1 of Part I of this report for further information about financings
during the first six months of 2003.
Off-Balance Sheet Arrangements
At June 30, 2003, neither Ameren, nor any of its subsidiaries, including
us, had any off-balance sheet financing arrangements, other than operating
leases entered into in the ordinary course of business.
OUTLOOK
We believe there will be challenges to earnings in 2003 and beyond due to
industry-wide trends and company-specific issues. The following are expected to
put pressure on earnings in 2003 and beyond:
o Weak economic conditions, which impacts native load demand;
o Power prices in the Midwest will impact the amount of revenues we can
generate by marketing any excess power into the interchange markets.
Long-term power prices continue to be generally soft in the Midwest,
despite the fact that short-term power prices have strengthened
significantly from the prior year in the first six months of 2003 due
primarily to higher prices for natural gas;
o 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 Fixed electric rates in our Illinois service territory;
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.
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 Ameren's overall cost;
o A wage freeze in 2003 for all management employees;
o Suspension of operations at a 1940's-era generating 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 $27 million in Missouri. See Note 2 - Rate and Regulatory Matters
to our Consolidated Financial Statements under Item 1 of Part I of this report
for additional information. Ameren is also considering additional actions
including modifications to active employee benefits, further staffing reductions
and other initiatives.
International Brotherhood of Electrical Workers and the International Union
of Operating Engineers labor agreements for six bargaining units covering
approximately 65% of our entire workforce expired between April 1 and July 1,
2003. The principal issues being negotiated with regard to continuation of these
labor agreements are wages, work rules and a proposal to change the employee
medical benefits program to require employees to pay for a greater portion of
their benefit coverage. During July 2003, after engaging in extensive
negotiations with the collective bargaining units, we finalized new tentative
agreements with five of the bargaining units with terms expiring in 2006. The
membership of three of the bargaining units have ratified the agreements with
respect to wages and work rules and the membership of the remaining bargaining
units are expected to vote on their new agreement in the third quarter of 2003.
Changes to the employee medical benefits program have been agreed to with a
joint bargaining committee representing all unions; however, the changes cannot
be implemented without ratification by a majority of the collective membership
of all bargaining units. We are unable to predict whether the agreements will be
ratified or what action, if any, the collective bargaining units will take in
the event the agreements are not ratified or the response of other
union-represented employees to any action by its employees. We are still
negotiating as to wages and work rules with one bargaining unit, which
represents approximately 30% of
22
our workforce. We are unable to determine what, if any, impact these labor
matters could have on our future financial condition, results of operations or
liquidity.
At December 31, 2002, Ameren recorded a minimum accumulated pension
liability of $102 million, after taxes, which resulted in a charge to
Accumulated Other Comprehensive Income (Loss) (OCI) and a reduction in
stockholder's equity. Our share of the minimum pension liability was
approximately $62 million, after taxes. Based on changes in interest rates,
Ameren expects it may need to change its actuarial assumptions for its pension
plan at December 31, 2003, which could result in a requirement to record an
additional minimum pension liability.
In the ordinary course of business, we and Ameren evaluate strategies to
enhance our financial position, results of operations and liquidity. These
strategies may include potential acquisitions, divestitures and opportunities to
reduce costs or increase revenues and other strategic initiatives in order to
increase Ameren's shareholder value. We are unable to predict which, if any, of
these initiatives will be executed, as well as the impact these initiatives may
have on our future financial position, results of operations or liquidity.
REGULATORY MATTERS
See Note 2 - Rate and Regulatory Matters to our Consolidated Financial
Statements under Item 1 of Part I of this report for information on our proposed
sale of our Illinois service terriory and our proposed purchase of 550 megawatts
of generating capacity, both with affiliates, and information on other
regulatory matters.
ACCOUNTING MATTERS
See Note 1 - Summary of Significant Accounting Policies to our Consolidated
Financial Statements under Item 1 of Part I of this report for information.
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 those of AmerenUE, 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 June 30, 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.
23
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
AmerenUE, along with other subsidiaries of Ameren, is a participant in
Ameren's defined benefit plans and postretirement benefit plans and are
responsible for our proportional share of the costs. Ameren's costs of providing
non-contributory defined benefit retirement and postretirement benefit plans are
dependent upon a number of factors, such as the rates of return on plan assets,
discount rate, the rate of increase in health care costs and contributions made
to the plans. The market value of Ameren's plan assets has been affected by
declines in the equity market since 2000 for the pension and postretirement
plans. As a result, at December 31, 2002, Ameren and its subsidiaries, including
us, recognized an additional minimum pension liability as prescribed by SFAS No.
87, "Employers' Accounting for Pensions." The liability resulted in a reduction
to equity as a result of a charge to Ameren's OCI of $102 million, net of taxes.
Our portion of this charge to OCI was $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. The minimum pension
liability did not change at June 30, 2003. In future years, the liability
recorded, the costs reflected in net income or OCI, or cash contributions to the
plans could increase materially without a recovery in equity markets in excess
of our assumed return on plan assets. If the fair value of the plan assets were
to grow and exceed the accumulated benefit obligations in the future, then the
recorded liability would be reduced and a corresponding amount of equity would
be restored in the 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
24
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 three and six months ended
June 30, 2003:
==================================================================================================
Three Six
months months
- --------------------------------------------------------------------------------------------------
Fair value of contracts at beginning of period, net $ 5 $ 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 (3) (3)
- --------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at end of period, net $ 3 $ 3
==================================================================================================
Maturities of contracts as of June 30, 2003 were as follows:
======================================================================================================================
Maturity Maturity
less than Maturity 1-3 Maturity in excess Total fair
Sources of fair value 1 year 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) 3 1 (1) - 3
- ----------------------------------------------------------------------------------------------------------------------
Total $ 4 $ - $ (1) $ - $ 3
- ----------------------------------------------------------------------------------------------------------------------
(a) Contracts of less than $1 million were with non-investment-grade rated
counterparties.
(b) Principally power forward values based on NYMEX prices for over-the-counter
contracts and natural gas swaps based primarily on Inside FERC.
(c) Principally coal and sulfur dioxide options valued based on a Black-Scholes
model that includes information from external sources and our estimates.
Also, includes power forward values based on our estimates.
ITEM 4. Controls and Procedures.
(a) Evaluation of Disclosure Controls and Procedures
As of June 30, 2003, the principal executive officer and principal
financial officer of AmerenUE have evaluated the effectiveness of the
design and operation of AmerenUE's disclosure controls and procedures (as
defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of
1934, as amended (Exchange Act)). Based upon that evaluation, the principal
executive officer and principal financial officer of AmerenUE have
concluded that such disclosure controls and procedures are effective in
timely alerting them to any material information relating to AmerenUE and
its consolidated subsidiaries, which is required to be included in
AmerenUE's reports filed or submitted with the SEC under the Exchange Act.
(b) Changes in Internal Control Over Financial Reporting
There has been no significant change in AmerenUE's internal control over
financial reporting that occurred during AmerenUE's most recent fiscal
quarter that has materially affected, or is reasonably likely to materially
affect, AmerenUE's internal control over financial reporting.
FORWARD-LOOKING STATEMENTS
Statements made in this report, which are not based on historical facts are
"forward-looking" and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those
25
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;
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;
o legal and administrative proceedings; and
o delays in or difficulties in connection with the receipt of regulatory
approvals with respect to AmerenUE's plan to discontinue operating as a
public utility subject to ICC regulation and the transferring of AmerenUE's
Illinois-based electric and natural gas businesses to AmerenCIPS or
unexpected adverse conditions or terms of those approvals.
Given these uncertainties, undue reliance should not be placed on these
forward-looking statements. Except to the extent required by the federal
securities laws, we undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
26
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings.
On June 18, 2003, twenty retirees and surviving spouses of retirees of our
parent, Ameren Corporation, or its predecessors or subsidiaries (the plaintiffs)
filed a complaint in the U.S. District Court, Southern District of Illinois,
against Ameren, and its subsidiaries, Central Illinois Public Service Company,
operating as AmerenCIPS, Ameren Energy Resources Company, Ameren Energy
Generating Company, Ameren Services Company and us, and against Ameren's Retiree
Medical Plan (the defendants). The retirees were members of various local labor
unions of the International Brotherhood of Electrical Workers (IBEW) and the
International Union of Operating Engineers (IUOE). The complaint alleges the
following:
o the labor organizations, which represented the plaintiffs, have
historically negotiated retiree medical benefits with the defendants and
that, pursuant to the negotiated collective bargaining agreements and other
negotiated documents, the plaintiffs are guaranteed medical benefits at no
cost or at a fixed maximum cost during their retirement;
o Ameren has unilaterally announced that, beginning in 2004, retirees must
pay a portion of their own health care premiums and either an increasing
portion of their dependents' premiums or newly imposed dependents'
premiums, and that surviving spouses will be paying increased amounts for
their medical benefits;
o the defendants' actions deprive the plaintiffs of vested benefits and thus
violate the Employee Retirement Income Security Act and the Labor
Management Relations Act of 1947, and constitute a breach of the
defendants' fiduciary duties; and
o the defendants are estopped from changing the plan benefits.
The plaintiffs have filed the complaint on behalf of themselves, other
similarly situated former non-management employees and their surviving spouses
who retired from January 1, 1992 through October 1, 2002, and on behalf of all
subsequent non-management retirees and their surviving spouses whose vested
medical benefits are reduced or are threatened with reduction. The plaintiffs
seek to have this lawsuit certified as a class action, injunctive relief and
declaratory relief, actual damages for any amounts they are made to pay as a
result of the defendants' actions, and payment of attorney fees and costs. On
August 11, 2003, the defendants filed motions to dismiss various counts of the
complaint. We are unable to predict the outcome of this lawsuit or the impact of
the outcome on our financial position, results of operations or liquidity.
Reference is made to Note 2 to the Notes to Consolidated Financial
Statements in our Form 10-Q for the quarterly period ended March 31, 2003 for a
discussion of the Missouri Supreme Court's opinion issued in April 2003
upholding the adoption of affiliate rules by the Missouri Public Service
Commission for Missouri's gas and electric utilities. We had originally appealed
the adoption of the asymmetric pricing provisions contained in the affiliate
rules. In May 2003, the Missouri Supreme Court denied our Motion for
Reconsideration of its April 2003 opinion, which makes the affiliate rules
applicable to us. We do not expect these rules to have a material adverse impact
on our future financial position, cash flows or results of operations.
Reference is made to Note 14 to the Notes to Financial Statements in Item
8. "Financial Statements and Supplementary Data" in Part II of our 2002
Consolidated Annual Report on Form 10-K, to 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, and to Item 1. "Legal Proceedings" in Part II of our
Form 10-Q for the quarterly period ended March 31, 2003, for a discussion of a
number of lawsuits that name our affiliates, 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 our Form 10-Q for the quarterly period ended March 31, 2003, eleven
additional lawsuits have been filed against the Ameren companies. These
lawsuits, like the previous cases, were mostly filed in the Circuit Court of
Madison County in Illinois, involve a large number of total defendants and seek
unspecified damages in excess of $50,000 in each case, which, if proved,
typically would be shared among the named defendants. Also since the filing of
our Form 10-Q for the quarterly period ended March 31, 2003, the Ameren
companies have settled one case. To date, a total of 164 asbestos-related
lawsuits have been filed against the Ameren companies, of which 84 are pending,
17 have been settled and 63 have been dismissed. Of these 164 lawsuits, we have
been specifically named as a defendant in 112, of which 53 are pending, 11 have
been settled and 48 have been dismissed. We
27
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 4. Submission of Matters To a Vote of Security Holders.
At our annual meeting of stockholders held on April 22, 2003, the election
of directors was presented to the meeting for a vote and the results of such
voting are as follows:
Non-Voted
Name For Withheld Brokers
---- --- -------- ---------
Paul A. Agathen 102,612,791 7,806 0
Warner L. Baxter 102,612,691 7,906 0
Richard A. Liddy 102,612,406 8,191 0
Richard A. Lumpkin 102,612,617 7,980 0
Paul L. Miller, Jr. 102,612,791 7,806 0
Charles W. Mueller 102,612,791 7,806 0
Douglas R. Oberhelman 102,612,143 8,454 0
Gary L. Rainwater 102,612,791 7,806 0
Harvey Saligman 102,612,707 7,890 0
Thomas R. Voss 102,612,791 7,806 0
David A. Whiteley 102,612,791 7,806 0
ITEM 5. Other Information.
Reference is made to Item 2. "Properties" in Part I of our 2002 Annual
Report on Form 10-K for a discussion of our membership in MAIN (Mid-America
Interconnected Network), which is one of the regional electric reliability
councils organized for coordinating the planning and operation of the nation's
bulk power supply. In response to the withdrawal notices filed by Commonwealth
Edison and Illinois Power, also members of MAIN, we, along with our affiliates,
AmerenCIPS and AmerenCILCO, provided formal written notice to the MAIN Board of
Directors on June 23, 2003 of our intent to withdraw from MAIN effective January
1, 2005. We intend to join another Regional Reliability Organization (RRO) prior
to our withdrawal from MAIN becoming effective. Until our withdrawal is
effective, we will continue to honor all of our obligations as a member of MAIN.
If we do not join another RRO, we may withdraw our notice of intent to withdraw
from MAIN.
Any stockholder proposal intended for inclusion in the proxy material for
our 2004 annual meeting of stockholders must be received by us by November 28,
2003. In addition, under our By-Laws, stockholders who intend to submit a
proposal in person at an annual meeting, or who intend to nominate a director at
a meeting, must provide advance written notice along with other prescribed
information. In general, such notice must be received by our Secretary not later
than 60 nor earlier than 90 days prior to the anniversary of the preceding
year's annual meeting. For our 2004 annual meeting of stockholders, written
notice of any in-person stockholder proposal or director nomination must be
received not later than February 22, 2004 or earlier than January 23, 2004. Our
2004 annual meeting of stockholders is scheduled to be held on April 27, 2004.
ITEM 6. Exhibits and Reports on Form 8-K.
(a) Exhibits filed herewith.
31.1 - Rule 13a -14(a)/15d-14(a) Certification of Principal
Executive Officer (required by Section 302 of
the Sarbanes-Oxley Act of 2002).
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31.2 - Rule 13a-14(a)/15d-14(a) Certification of Principal
Financial Officer (required by Section 302 of
the Sarbanes-Oxley Act of 2002).
32.1 - Section 1350 Certification of Principal Executive Officer
(required by Section 906 of the Sarbanes-Oxley Act of
2002).
32.2 - Section 1350 Certification of Principal Financial Officer
(required by Section 906 of the Sarbanes-Oxley Act of
2002).
(b) Reports on Form 8-K. Union Electric Company filed the following
reports on Form 8-K during the quarterly period ended June 30,
2003:
======================================================================
Items Financial
Date of Report Reported Statements Filed
----------------------------------------------------------------------
April 9, 2003 5, 7 None
May 23, 2003 5, 7 None
May 30, 2003 5 None
Note: Reports of Ameren Corporation on Forms 8-K, 10-Q and 10-K are on
file with the SEC under File Number 1-14756.
Reports of 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.
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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: August 14, 2003
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