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, 2002
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For The Transition Period From to
Commission file number 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 .
------------ ------------
Shares outstanding of each of the registrant's classes of common stock as of
August 9, 2002:
Common Stock, $5 par value, held by Ameren Corporation (parent company of
registrant) - 102,123,834
UNION ELECTRIC COMPANY
INDEX
Page
----
PART I. Financial Information
ITEM 1. Financial Statements (Unaudited)
Balance Sheet at June 30, 2002 and December 31, 2001......... 2
Statement of Income for the three and six months ended
June 30, 2002 and 2001...................................... 3
Statement of Cash Flows for the six months ended
June 30, 2002 and 2001...................................... 4
Statement of Common Stockholder's Equity for the three
and six months ended June 30, 2002 and 2001................. 5
Notes to Financial Statements................................ 6
ITEM 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 13
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk... 21
PART II. Other Information
ITEM 1. Legal Proceedings............................................ 24
ITEM 4. Submission of Matters to a Vote of Security Holders.......... 24
ITEM 5. Other Information............................................ 24
ITEM 6. Exhibits and Reports on Form 8-K............................. 25
SIGNATURE............................................................... 26
1
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
UNION ELECTRIC COMPANY
BALANCE SHEET
(Unaudited, in millions, except per share amounts)
June 30, December 31,
2002 2001
---------- -------------
ASSETS:
Property and plant, at original cost:
Electric $ 10,165 $ 9,828
Gas 259 252
Other 37 37
---------- ------------
10,461 10,117
Less accumulated depreciation and amortization 4,913 4,802
---------- ------------
5,548 5,315
Construction work in progress:
Nuclear fuel in process 114 97
Other 161 298
---------- ------------
Total property and plant, net 5,823 5,710
---------- ------------
Investments and other assets:
Nuclear decommissioning trust fund 175 187
Other 96 75
---------- ------------
Total investments and other assets 271 262
---------- ------------
Current assets:
Cash and cash equivalents 8 15
Accounts receivable - trade (less allowance for doubtful
accounts of $9 and $7, respectively) 180 144
Unbilled revenue 166 90
Other accounts and notes receivable 24 73
Intercompany notes receivable - 84
Materials and supplies, at average cost -
Fossil fuel 62 71
Other 86 85
Other 12 16
---------- ------------
Total current assets 538 578
---------- ------------
Regulatory assets:
Deferred income taxes 579 604
Other 128 134
---------- ------------
Total regulatory assets 707 738
---------- ------------
Total Assets $ 7,339 $ 7,288
========== ============
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 1,442 1,440
Accumulated other comprehensive income 1 1
---------- ------------
Total common stockholder's equity 2,656 2,654
---------- ------------
Preferred stock not subject to mandatory redemption 155 155
Long-term debt 1,599 1,599
---------- ------------
Total capitalization 4,410 4,408
---------- ------------
Current liabilities:
Current maturities of long-term debt 98 92
Short-term debt - 186
Intercompany notes payable 260 -
Accounts and wages payable 186 305
Accumulated deferred income taxes 35 35
Taxes accrued 186 104
Other 140 128
---------- ------------
Total current liabilities 905 850
---------- ------------
Accumulated deferred income taxes 1,291 1,326
Accumulated deferred investment tax credits 126 129
Regulatory liabilities 138 137
Other deferred credits and liabilities 469 438
---------- ------------
Total Capital and Liabilities $ 7,339 $ 7,288
========== ============
See Notes to Financial Statements.
2
UNION ELECTRIC COMPANY
STATEMENT OF INCOME
(Unaudited, in millions)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- --------------------
2002 2001 2002 2001
---- ---- ---- ----
OPERATING REVENUES:
Electric $ 732 $ 765 $ 1,416 $ 1,362
Gas 18 18 68 87
------- ------- --------- ---------
Total operating revenues 750 783 1,484 1,449
------- ------- --------- ---------
OPERATING EXPENSES:
Operations
Fuel and purchased power 210 261 504 480
Gas 10 11 42 57
Other 139 133 268 263
------- ------- --------- ---------
359 405 814 800
Maintenance 68 101 123 159
Depreciation and amortization 69 70 141 139
Income taxes 53 48 81 79
Other taxes 55 53 107 103
------- ------- --------- ---------
Total operating expenses 604 677 1,266 1,280
------- ------- --------- ---------
OPERATING INCOME 146 106 218 169
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction 1 3 2 4
Miscellaneous, net -
Miscellaneous income 17 4 23 17
Miscellaneous expense 29) (3) (31) (7)
Income taxes (1) 1 (2) (1)
------- ------- --------- ---------
Total other income and (deductions) (12) 5 (8) 13
------- ------- --------- ---------
INTEREST CHARGES:
Interest 27 31 54 61
Allowance for borrowed funds used during construction - (2) (2) (4)
------- ------- --------- ---------
Net interest charges 27 29 52 57
------- ------- --------- ---------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 107 82 158 125
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES - - - (5)
------- ------- --------- ---------
NET INCOME 107 82 158 120
PREFERRED STOCK DIVIDENDS 2 2 4 4
------- ------- --------- ---------
NET INCOME AFTER PREFERRED STOCK DIVIDENDS $ 105 $ 80 $ 154 $ 116
======= ======= ========= =========
See Notes to Financial Statements.
3
UNION ELECTRIC COMPANY
STATEMENT OF CASH FLOWS
(Unaudited, in millions)
Six Months Ended
June 30,
-------------------------
2002 2001
---- ----
Cash Flows From Operating:
Net income $ 158 $ 120
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting principle - 5
Depreciation and amortization 141 139
Amortization of nuclear fuel 16 12
Amortization of debt issuance costs and premium/discounts 2 2
Allowance for funds used during construction (4) (8)
Deferred income taxes, net (9) 15
Deferred investment tax credits, net (3) (1)
Other - (4)
Changes in assets and liabilities:
Receivables, net (63) (48)
Materials and supplies 8 (17)
Accounts and wages payable (119) (29)
Taxes accrued 82 81
Assets, other (9) (8)
Liabilities, other 43 (34)
--------- ---------
Net cash provided by operating activities 243 225
--------- ---------
Cash Flows From Investing:
Construction expenditures (246) (253)
Allowance for funds used during construction 4 8
Nuclear fuel expenditures (16) (12)
Intercompany notes receivable 84 78
--------- ---------
Net cash used in investing activities (174) (179)
--------- ---------
Cash Flows From Financing:
Dividends on common stock (152) (141)
Dividends on preferred stock (4) (4)
Redemptions:
Nuclear fuel lease - (64)
Short-term debt (186) -
Issuances:
Nuclear fuel lease 6 2
Long-term debt - 146
Intercompany notes payable 260 -
--------- ---------
Net cash used in financing activities (76) (61)
--------- ---------
Net change in cash and cash equivalents (7) (15)
Cash and cash equivalents at beginning of year 15 20
--------- ---------
Cash and cash equivalents at end of period $ 8 $ 5
========= =========
Cash paid during the periods:
Interest $ 48 $ 53
Income taxes, net 63 31
See Notes to Financial Statements.
4
UNION ELECTRIC COMPANY
STATEMENT OF COMMON STOCKHOLDER'S EQUITY
(Unaudited, in millions)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------- -----------------------
2002 2001 2002 2001
---- ---- ---- ----
Common stock $ 511 $ 511 $ 511 $ 511
Other paid-in capital 702 702 702 702
Retained earnings
Beginning balance 1,413 1,340 1,440 1,358
Net income 107 82 158 120
Common stock dividends (76) (87) (152) (141)
Preferred stock dividends (2) (2) (4) (4)
----------- ----------- ---------- ---------
1,442 1,333 1,442 1,333
----------- ----------- ---------- ---------
Accumulated other comprehensive income
Beginning balance (1) (2) 1 -
Change in current period (see below) 2 (2) - (4)
----------- ----------- ---------- ---------
1 (4) 1 (4)
----------- ----------- ---------- ---------
Total common stockholder's equity $ 2,656 $ 2,542 $2,656 2,542
=========== =========== ========== =========
Comprehensive income, net of taxes
Net income $ 107 $ 82 $ 158 $ 120
Unrealized net gain/(loss) on derivative hedging instruments
(net of income taxes of $1, $(2), $1 and $(1), respectively) 1 (3) 2 (2)
Reclassification adjustments for gains/(losses) included in net income
(net of income taxes of $ -, $1, $(1) and $4, respectively) 1 1 (2) 6
Cumulative effect of accounting change, net of income taxes of $(5) - - - (8)
----------- ----------- ---------- ---------
Total comprehensive income, net of taxes $ 109 $ 80 $ 158 $ 116
=========== =========== ========== =========
See Notes to Financial Statements.
5
UNION ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
June 30, 2002
NOTE 1 - Summary of Significant Accounting Policies
Basis of Presentation
Our financial statements reflect all adjustments (which include normal,
recurring adjustments) necessary, in our opinion, for a fair presentation of the
interim results. These statements should be read in conjunction with the
financial statements and the notes thereto included in our 2001 Annual Report on
Form 10-K.
When we refer to AmerenUE, our, we or us, we are referring to Union
Electric Company. All dollar amounts are in millions, unless otherwise
indicated.
Accounting Changes
In January 2001, we adopted Statement of Financial Accounting Standards
(SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities."
The impact of that adoption resulted in a cumulative effect charge of $5 million
after taxes to the income statement, and a cumulative effect adjustment of $8
million, after taxes, to Accumulated Other Comprehensive Income (OCI), which
reduced common stockholder's equity.
On January 1, 2002, we adopted SFAS No. 141, "Business Combinations," and
SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS 141 requires business
combinations to be accounted for under the purchase method of accounting, which
requires one party in the transaction to be identified as the acquiring
enterprise and for that party to allocate the purchase price to the assets and
liabilities of the acquired enterprise based on fair market value. SFAS 142
requires goodwill and indefinite-lived intangible assets recorded in the
financial statements to be tested for impairment at least annually, rather than
amortized over a fixed period, with impairment losses recorded in the income
statement. SFAS 141 and SFAS 142 did not have any effect on our financial
position, results of operations or liquidity upon adoption. See Note 6 -
"CILCORP Acquisition."
In July 2001, SFAS No. 143, "Accounting for Asset Retirement Obligations,"
was issued. SFAS 143 requires an entity to record a liability and corresponding
asset representing the present value of legal obligations associated with the
retirement of tangible, long-lived assets. SFAS 143 is effective for us on
January 1, 2003. At this time, we are assessing the impact of SFAS 143 on our
financial position, results of operations and liquidity upon adoption. However,
as a result of this new standard we expect significant increases to our reported
assets and liabilities, including those resulting from obligations associated
with our Callaway nuclear plant's decommissioning costs and associated
regulatory rate cost recovery.
On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." SFAS 144 addresses the financial accounting
and reporting for the impairment or disposal of long-lived assets and supersedes
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of." SFAS 144 retains the guidance related to calculating
and recording impairment losses, but adds guidance on the accounting for
discontinued operations, previously accounted for under Accounting Principles
Board Opinion No. 30. We evaluate long-lived assets for impairment when events
or changes in circumstances indicate that the carrying value of such assets may
not be recoverable. The determination of whether impairment has occurred is
based on an estimate of undiscounted cash flows attributable to the assets, as
compared with the carrying value of the assets. If impairment has occurred, the
amount of the impairment recognized is determined by estimating the fair value
of the assets and recording a provision for loss if the carrying value is
greater than the fair value. SFAS 144 did not have any effect on our financial
position, results of operations or liquidity upon adoption.
Historically, 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 - Operations -
Fuel and Purchased Power in our income statement. This means that revenues were
recorded for the notional amount of the power sale contracts with a
corresponding charge to income for the cost of the energy that has been
generated or for the notional amount of a purchased power contract. In June
2002, the Emerging Issues Task Force (or EITF) reached a consensus in Issue
02-03, "Accounting
6
for Contracts Involved in Energy Trading and Risk Management Activities," that
certain energy contracts should be shown on a net basis in the income statement.
The consensus on this issue is applicable to financial statements for periods
ending after July 15, 2002, with a requirement to conform prior periods to this
presentation. As a result of the EITF's accounting guidance and other factors
that exist within our industry, beginning with the period ending September 30,
2002, we will change our accounting practice to present, on a net basis in our
income statement, all contracts within our power risk management program that
have been net settled. All prior periods included in our prospective financial
statements will be reclassified to reflect this change in accounting practice.
We are still in the process of evaluating the impact of this change to our
income statement, but our revenues and operating expenses will be reduced in
future periods with no impact on our earnings. See Note 4 - "Derivative
Financial Instruments" for more information.
Interchange Revenues
Interchange revenues included in Operating Revenues - Electric were $140
million for the three months ended June 30, 2002 (2001 - $161 million) and $369
million for the six months ended June 30, 2002 (2001 - $324 million).
Purchased Power
Purchased power included in Operating Expenses, Operations - Fuel and
Purchased Power was $131 million for the three months ended June 30, 2002 (2001
- - $184 million) and $346 million for the six months ended June 30, 2002 (2001 -
$310 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 applicable to Illinois electric customer bills are imposed on the
consumer and are recorded as tax collections payable. Excise taxes recorded in
Operating Revenues and Other Taxes for the three months ended June 30, 2002 were
$28 million (2001 - $25 million) and $49 million for the six-month period ended
June 30, 2002 (2001 - $46 million).
NOTE 2 - Rate and Regulatory Matters
Missouri Electric
From July 1, 1995 through June 30, 2001, we operated under experimental
alternative regulation plans in Missouri that provided for the sharing of
earnings with customers if our regulatory return on equity exceeded defined
threshold levels. After our experimental alternative regulation plan for our
Missouri retail electric customers expired, the Missouri Public Service
Commission (MoPSC) Staff filed an excess earnings complaint against us with the
MoPSC in July 2001. In March 2002, the MoPSC Staff filed a recommendation that
we reduce our annual Missouri electric revenues by $246 million to $285 million.
The MoPSC Staff's recommendation was based on a return to traditional cost of
service ratemaking, a lowered return on equity, a reduction in our depreciation
rates and other cost of service adjustments. In May 2002, we filed testimony
supporting a rate increase of at least $150 million and proposed a new
alternative regulation plan that included a rate decrease.
On July 16, 2002, AmerenUE, the MoPSC Staff, and all of the other parties
to the proceeding submitted to the MoPSC a stipulation and agreement resolving
this case. On July 24, 2002, the MoPSC held a hearing on the stipulation and
agreement. On July 25, 2002, the MoPSC approved the stipulation and agreement,
and on August 4, 2002, it became effective. The stipulation and agreement
includes the following principal features:
o the phase-in of $110 million of electric rate reductions through April
2004, $50 million of which is retroactively effective as of April 1,
2002, $30 million of which will become effective on April 1, 2003, and
$30 million of which will become effective on April 1, 2004,
o a rate moratorium providing for no requests for changes in our
electric rates as established by the stipulation and agreement before
January 1, 2006 and no resulting changes in rates before June 30,
2006, subject to certain statutory and other exceptions,
7
o a commitment to contribute, as early as September 2002, $14 million to
programs for low income energy assistance and weatherization,
promotion of energy efficiency and economic development in our service
territory, with additional payments of $3 million made annually on
June 30, 2003 through June 30, 2006,
o a commitment to make $2.25 billion to $2.75 billion in critical energy
infrastructure investments from January 1, 2002 through June 30, 2006,
including, among other things, the addition of more than 700 megawatts
of new generation capacity and the replacement of steam generators at
our nuclear power plant. The 700 megawatts of new generation includes
240 megawatts already added this year and may include the transfer at
book value to us of generation assets from our non-regulated
affiliates. The amount of energy infrastructure investments through
June 2006 described in the stipulation and agreement is consistent
with our previously-disclosed estimate of the construction
expenditures we expect to make over the same time period,
o an annual reduction in our depreciation rates by $20 million,
retroactive to April 1, 2002, based on an updated analysis of asset
values, service lives and accumulated depreciation levels, and
o a one-time credit of $40 million to be paid to our Missouri retail
electric customers as early as August 2002 for settlement of the final
sharing period under the alternative regulation plan that expired June
30, 2001. At June 30, 2002, we had accrued $40 million in Current
Liabilities - Other.
In total, the stipulation and agreement is estimated to reduce 2002 net
earnings by $32 million. Net earnings are expected to be reduced in 2002 due to
the rate reduction ($26 million, net of taxes, including $8 million, net of
taxes, in the quarter ended June 30, 2002), the expensing in the quarter ended
June 30, 2002 of the entire obligation to fund certain programs ($15 million,
net of taxes), offset, in part, by the reduction in depreciation expense ($9
million, net of taxes, including $3 million, net of taxes, in the quarter ended
June 30, 2002). Net earnings were reduced by $20 million in the quarter ended
June 30, 2002 due to the stipulation and agreement. We expect earnings to be
reduced by $9 million in the third quarter of 2002 and $3 million in the fourth
quarter of 2002.
In order to satisfy our regulatory load requirements for 2001, we
purchased, under a one year contract, 450 megawatts of capacity and energy from
our affiliate, AmerenEnergy Marketing Company (Marketing Company) (the 2001
Marketing Company - AmerenUE agreement). This agreement was entered into through
a competitive bidding process and reflected market-based rates. For 2002, we
similarly entered into a one-year contract with Marketing Company for the
purchase of 200 megawatts of capacity and energy (the 2002 Marketing Company -
AmerenUE agreement). For the four summer months of 2002, we also entered into
contracts with two other power suppliers for an aggregate 200 megawatts of
additional capacity and energy.
In May 2001, the MoPSC filed a complaint with the Securities and Exchange
Commission (SEC) relating to the 2001 Marketing Company - AmerenUE agreement.
The complaint requested an investigation into the contractual relationship
between AmerenUE, Marketing Company and AmerenEnergy Generating Company
(Generating Company), also our affiliate, in the context of the 2001 Marketing
Company - AmerenUE agreement and requests that the SEC find that such
relationship violates a provision of the Public Utility Holding Company Act of
1935 (or PUHCA), which requires state utility commission approval of power sales
contracts between an electric utility company and an affiliated electric
wholesale generator, like Generating Company. We believe that the MoPSC's
approval of the power sales agreement under PUHCA is not required because
Generating Company is not a party to the agreement. As a remedy, the MoPSC
proposes that the SEC require us to contract directly with Generating Company
and submit such contract to the MoPSC for review. On May 9, 2002, the MoPSC
filed a similar complaint with the SEC relating to the 2002 Marketing Company -
AmerenUE agreement. The SEC is investigating these matters. Also, with respect
to the 2002 Marketing Company - AmerenUE agreement, on May 31, 2002, the Federal
Energy Regulatory Commission (FERC) accepted the agreement, subject to refund,
and scheduled the matter for a January 2003 hearing to assess the
appropriateness of the rates charged. At this time, management is unable to
predict the outcome of these proceedings or the ultimate impact on our future
financial position, results of operations or liquidity.
Illinois
In December 1997, the Electric Service Customer Choice and Rate Relief Law
of 1997 (the Illinois Law) was enacted providing for electric utility
restructuring in Illinois. This legislation introduced competition into the
retail supply of electric energy in Illinois. Illinois residential customers
were offered choice in suppliers on May 1, 2002. Industrial and commercial
customers were previously offered this choice.
8
The Illinois Law contained a provision freezing retail bundled electric
rates through January 1, 2005. In 2002, legislation was passed and signed into
law that extended the rate freeze period through January 1, 2007. The offering
of choice to our industrial and commercial customers has not had a material
adverse effect on our business and we do not expect the offering of choice to
our residential customers, or the extension of the rate freeze, to have a
material adverse effect on our business.
Federal - Regional Transmission Organizations
In December 1999, the FERC issued Order 2000, requiring all utilities,
subject to FERC jurisdiction, to state their intentions for joining a regional
transmission organization (RTO). RTOs are independent organizations that will
functionally control the transmission assets of utilities in order to improve
the wholesale power market. Since January 2001, we, along with several other
utilities, were seeking approval from the FERC to participate in an RTO known as
the Alliance RTO. We had previously been a member of the Midwest Independent
System Operator (MISO) and recorded a pretax charge to earnings in 2000 of $17
million ($10 million after taxes) for an exit fee and other costs when we left
that organization. We felt the for-profit Alliance RTO business model was
superior to the not-for-profit MISO business model and provided us with a more
equitable return on our transmission assets.
In late 2001, the FERC issued an order that rejected the formation of the
Alliance RTO and ordered the Alliance RTO companies and the MISO to discuss how
the Alliance RTO business model could be accommodated within the MISO. On April
25, 2002, after the Alliance RTO and MISO failed to reach an agreement, and
after a series of filings by the two parties with the FERC, the FERC issued a
declaratory order setting forth the division of responsibilities between the
MISO and National Grid (the managing member of the transmission company formed
by the Alliance companies) and approved the rate design and the revenue
distribution methodology proposed by the Alliance companies. However, the FERC
denied a request by the Alliance companies and the National Grid to purchase
certain services from the MISO at incremental cost rather than MISO's full
tariff rates. The FERC also ordered the MISO to return the exit fee paid by
AmerenUE to leave the MISO, provided AmerenUE returns to the MISO and agrees to
pay its proportional share of the startup and ongoing operational expenses of
the MISO. Moreover, the FERC required the Alliance companies to select the RTO
in which they will participate within thirty days of the order.
Since the April 2002 FERC order, we and our affiliate, Central Illinois
Public Service Company (known as AmerenCIPS) made filings with the FERC
indicating that we would return to the MISO and that membership would be through
a new independent transmission company, GridAmerica LLC, that was agreed to be
formed by AmerenUE and AmerenCIPS, along with subsidiaries of FirstEnergy
Corporation and NiSource Inc. If the FERC approves the definitive agreements
establishing GridAmerica, National Grid will serve as the managing member of
GridAmerica and will manage the transmission assets of the three companies and
participate in the MISO on behalf of GridAmerica. Other Alliance RTO companies
announced their intentions to join the Pennsylvania - Jersey - Maryland (PJM)
RTO. On July 25, 2002, the Ameren companies filed a motion with the FERC
requesting that it condition the approval of the choices of other Illinois
utilities to join the PJM RTO on MISO and PJM entering into an agreement
addressing important reliability and rate-barrier issues. On July 31, 2002, the
FERC issued an order accepting the formation of GridAmerica as an independent
transmission company under the MISO subject to further compliance filings
ordered by the FERC. The FERC also issued an order accepting the elections made
by the other Illinois utilities to join the PJM RTO on the condition PJM and
MISO immediately begin a process to address the reliability and rate-barrier
issues raised by the Ameren companies and other market participants in previous
filings.
Until the reliability and rate-barrier issues are resolved as ordered by
the FERC, and the tariffs and other material terms of our participation in
GridAmerica, and GridAmerica's participation in the MISO, are finalized and
approved by the FERC, we are unable to predict whether the Ameren companies will
in fact become a member of GridAmerica or MISO, or the impact that on-going RTO
developments will have on our financial condition, results of operation or
liquidity.
NOTE 3 - Related Party Transactions
AmerenUE has transactions in the normal course of business with its parent,
Ameren Corporation (Ameren), and its other subsidiaries. These transactions are
primarily comprised of power purchases and
9
sales, as well as other services received or rendered. Intercompany power
purchases from joint dispatch and other agreements were approximately $23
million for the three months ended June 30, 2002 (2001 - $21 million) and $50
million for the six months ended June 30, 2002 (2001 - $44 million).
Intercompany power sales totaled $17 million for the three months ended June 30,
2002 (2001 - $12 million) and $37 million for the six months ended June 30, 2002
(2001 - $40 million).
Support services provided by our affiliates, Ameren Services Company and
AmerenEnergy, Inc., including wages, employee benefits and professional services
are based on actual costs incurred. For the three months ended June 30, 2002,
Other Operating Expenses provided by Ameren Services and AmerenEnergy totaled
$48 million (2001 - $43 million) and $96 million (2001 - $90 million) for the
six months ended June 30, 2002.
We have the ability to borrow from Ameren and AmerenCIPS through a
regulated money pool agreement. Ameren Services administers the regulated money
pool and tracks internal and external funds separately. Internal funds are
surplus funds contributed to the money pool from participants. The primary
source of external funds for the regulated money pool at June 30, 2002 was our
commercial paper program, which was backed by bank credit agreements totaling
$430 million. The total amount available to us at any given time from the
regulated money pool is reduced by the amount of borrowings by our affiliates,
but increased to the extent Ameren, AmerenCIPS or Ameren Services have surplus
funds and the availability of other external borrowing sources. The availability
of funds is also determined by funding requirement limits established by PUHCA.
AmerenUE, AmerenCIPS and Ameren Services rely on the regulated money pool to
coordinate and provide for certain short-term cash and working capital
requirements. Borrowers receiving a loan under the regulated 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 regulated money pool. For the
three months ended June 30, 2002, the average interest rate for the regulated
money pool was 1.75% (2001 - 4.38%) and for the six months ended June 30, 2002
was 1.77% (2001 - 4.94%). As of June 30, 2002, we had the ability to borrow up
to $425 million, all of which was unused and available, through the regulated
money pool, which was in addition to amounts available under our $430 million
commercial paper program. At June 30, 2002, we had outstanding intercompany
payables of $260 million, sourced by internal funds through the money pool. At
December 31, 2001, we had outstanding intercompany receivables of $84 million
through the money pool.
In July 2002, Ameren entered into new credit agreements for $400 million in
revolving credit facilities to be used for general corporate purposes, including
support of commercial paper programs. The $400 million in new facilities
includes a $270 million 364-day revolving credit facility and a $130 million
3-year revolving credit facility. The 3-year facility has a $50 million
sub-limit for the issuance of letters of credit. These new credit facilities
replaced our existing $300 million revolving credit facility that was in place
as of June 30, 2002 with a maturity of August 15, 2002. There were no amounts
outstanding under this facility at June 30, 2002. In July 2002, we also did not
renew a $25 million committed line of credit. As a result of these changes in
facilities, at July 31, 2002, we had the ability to borrow up to $500 million,
all of which was unused and available, from Ameren through our regulated money
pool agreement.
Intercompany receivables included in Other Accounts and Notes Receivable
were approximately $15 million as of June 30, 2002 (December 31, 2001 - $38
million). Intercompany payables included in Accounts and Wages Payable totaled
approximately $50 million as of June 30, 2002 (December 31, 2001 - $70 million).
NOTE 4 - Derivative Financial Instruments
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 in inventory or under the
firm commitment; and
o actual cash outlays for the purchase of these commodities in certain
circumstances to differ from anticipated cash outlays.
10
The derivatives that we use to hedge these risks are dictated by risk
management policies and include forward contracts, futures contracts, options
and swaps. We continually assess our supply and delivery commitment positions
against forward market prices and internal forecasts of forward prices. We
actively manage our exposure to power price risk through our power risk
management program carried out under our risk management guidelines to modify
our exposure to market, credit and operational risk by entering into various
offsetting transactions. In general, we believe these transactions serve to
reduce price risk for us.
In addition, we may purchase additional megawatts, again within risk
management guidelines, in anticipation of future price changes. Certain
derivative contracts we enter into on a regular basis as part of our power risk
management program do not qualify for hedge accounting or the normal purchase,
normal sale exception under SFAS 133. Accordingly, these contracts are recorded
at fair value with changes in the fair value charged or credited to the income
statement in the period in which the change occurred. Contracts we enter into as
part of our power risk management program may be settled by either physical
delivery or financially settled with the counterparty. See Note 1 - "Summary of
Significant Accounting Policies."
As of June 30, 2002, we recorded the fair value of derivative financial
instrument assets of $21 million in Other Assets and the fair value of
derivative financial instrument liabilities of $19 million in Other Deferred
Credits and Liabilities.
Cash Flow Hedges
We routinely enter into forward purchase and sales contracts for
electricity based on forecasted levels of economic generation and load
requirements. The relative balance between load and economic generation varies
throughout the year. The contracts typically cover a period of twelve months or
less. The purpose of these contracts is to hedge against possible price
fluctuations in the spot market for the period covered under the contracts. We
formally document all relationships between hedging instruments and hedged
items, as well as our risk management objective and strategy for undertaking
various hedge transactions. The mark-to-market value of cash flow hedges will
continue to fluctuate with changes in market prices up to contract expiration.
For the three months ended June 30, 2002, the pretax net loss on power
forward derivative instruments, which represented the impact of discontinued
cash flow hedges, the ineffective portion of cash flow hedges, as well as the
reversal of amounts previously recorded in OCI due to transactions going to
delivery or settlement, was approximately $1 million. The loss from these
transactions for the three months in the prior year was immaterial. For the six
months ended June 30, 2002, the second quarter loss on power forward derivative
instruments offset the gain of $1 million from the first quarter. In the prior
year six-month period, we recognized a pretax net gain of $6 million.
As of June 30, 2002, we had hedged a portion of the price exposure related
to the relative balance between load and economic generation for the upcoming
twelve-month period. The mark-to-market value accumulated in OCI for the
effective portion of hedges of electricity price exposure is a net loss of
approximately $4 million ($2 million, net of taxes).
We also hold a call option for coal deliverable in 2004 with a supplier.
This option to purchase coal expires in October 2003. As of June 30, 2002, the
mark-to-market value accumulated in OCI is a gain of $5 million ($3 million, net
of taxes). The final value of the option 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, heating oil, and electricity. Most of these transactions are
treated as non-hedge transactions under SFAS 133. The net change in the market
value of sulfur dioxide options is recorded as Operating Revenues - Electric
Revenues, while the net change in the market value of coal, heating oil, and
electricity options is recorded as Operating Expense - Operations - Fuel and
Purchased Power in the income statement. The net change in the market values of
sulfur dioxide options, coal, heating oil, and electricity options was a gain of
$2 million for the three months ended June 30, 2002 and $3 million for the six
months ended June 30, 2002.
11
The change in market values in the prior year
resulted in losses of $2 million for the three-month period and $4 million for
the six-month period.
NOTE 5 - Miscellaneous, Net
Miscellaneous, net for the three and six months ended June 30, 2002 and
2001 consisted of the following:
- ------------------------------------------------------ --------------------- ---------------------
Three Months Six Months
- ------------------------------------------------------ --------------------- ---------------------
2002 2001 2002 2001
---- ---- ---- ----
Miscellaneous income:
Interest and dividend income $ 2 $ 2 $ 2 $ 6
Equity in earnings of subsidiary 10 1 11 2
Gain on disposition of property and other assets 5 - 8 8
Other - 1 2 1
- --------------------------------------------------------------------------------------------------
Total miscellaneous income $ 17 $ 4 $ 23 $ 17
- --------------------------------------------------------------------------------------------------
Miscellaneous expense:
Plant acquisition amortization $ - $ - $ (1) $ (1)
Loss on disposition of property and other assets (1) (2) - (4)
Donations - rate settlement (26) - (26) -
Other (2) (1) (4) (2)
- --------------------------------------------------------------------------------------------------
Total miscellaneous expense $(29) $ (3) $(31) $ (7)
- --------------------------------------------------------------------------------------------------
NOTE 6 - CILCORP Acquisition
On April 28, 2002, Ameren entered into an agreement with The AES
Corporation to purchase all of the outstanding stock of CILCORP Inc. CILCORP is
the parent company of Peoria-based Central Illinois Light Company, which
operates as CILCO. Ameren also agreed to acquire AES Medina Valley (No. 4),
L.L.C. which indirectly owns a 40 megawatt, gas-fired electric generation plant.
The total purchase price is approximately $1.4 billion, subject to adjustment
for changes in CILCORP's working capital, and includes the assumption of CILCORP
and AES Medina Valley debt at closing, estimated at approximately $900 million,
with the balance of the purchase price in cash. Ameren expects to finance a
significant portion of the cash component of the purchase price through the
issuance of new common equity.
The purchase will include CILCORP's regulated natural gas and electric
businesses in Illinois serving approximately 205,000 and 200,000 customers,
respectively, of which approximately 150,000 are combination electric and gas
customers. In addition, the purchase includes approximately 1,200 megawatts of
largely coal-fired generating capacity, most of which is expected to be
non-regulated by closing.
Upon completion of the acquisition, expected by March 2003, CILCO will
become an Ameren subsidiary, but will remain a separate utility company,
operating as AmerenCILCO. The transaction is subject to the approval of the
Illinois Commerce Commission, the SEC, the FERC, the expiration of the waiting
period under the Hart-Scott-Rodino Act, the Federal Communications Commission
and other customary closing conditions.
For the period ended December 31, 2001, CILCORP had revenues of $815
million, operating income of $126 million, and net income from continuing
operations of $28 million, and as of December 31, 2001 had total assets of $1.8
billion.
12
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
OVERVIEW
Union Electric Company is a wholly-owned subsidiary of Ameren Corporation
and operates as AmerenUE. Our principal business is the regulated generation,
transmission and distribution of electricity, and the regulated distribution of
natural gas to residential, commercial, industrial and wholesale users in
Missouri and Illinois. Ameren Corporation is a holding company registered under
the Public Utility Holding Company Act of 1935 (PUHCA). 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 regulated
electric and natural gas transmission and distribution business in
Illinois as AmerenCIPS.
o AmerenEnergy Resources Company (Resources Company), which consists of
non-regulated operations. Subsidiaries include AmerenEnergy Generating
Company (Generating Company) that operates non-regulated electric
generation in Missouri and Illinois, AmerenEnergy Marketing Company
(Marketing Company) which markets power for periods over one year, and
AmerenEnergy Fuels and Services Company, which procures fuel and
manages the related risks for Ameren affiliated companies.
o AmerenEnergy, Inc. 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 owns and/or 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. Our affiliate, Resources Company, also owns a
20% interest.
o Ameren Services Company, 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 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 audited financial statements and related notes that are included
in our Annual Report on Form 10-K for the period ended December 31,
2001.
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, 2001.
When we refer to AmerenUE, our, we or us, we are referring to Union
Electric Company. All dollar amounts are in millions, unless otherwise
indicated.
Our results of operations and financial position are impacted by many
factors, including both controllable and uncontrollable factors. Weather,
economic conditions, and the actions of key customers or competitors can
significantly impact the demand for our services. Our results are also
impacted by seasonal fluctuations caused by winter heating, and summer
cooling, demand. With nearly all of our revenues 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 and natural gas in our operations. The prices
for these commodities can fluctuate significantly due to the world economic
and political environment, weather, production levels and many other
factors. We do not have fuel recovery mechanisms in Missouri and Illinois,
but do have gas cost recovery mechanisms in each state. 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.
13
RESULTS OF OPERATIONS
Summary
Our net income increased 30% to $107 million in the second quarter of 2002,
from $82 million in the second quarter of 2001. Earnings for the six months
ended June 30, 2002, were $158 million, an increase of $38 million from the
first six months of 2001. The increase in both periods was primarily due to
favorable weather conditions (second quarter - $11 million; year to date - $6
million), increased sales of emission credits, including EEI (second quarter -
$9 million; year to date - $17 million), and the lack of a Callaway nuclear
plant refueling outage to date in 2002 (second quarter - $16 million; year to
date - $19 million). These increases were partially offset by the impact of the
settlement of our Missouri electric rate case (second quarter and year to date -
$20 million) (see below) and a reduction of an accrual in 2001 (second quarter -
$15 million; year to date - $6 million) for expected customer sharing credits
under the Missouri experimental alternative regulation plan that expired in June
2001 (see Note 2 - "Rate and Regulatory Matters" to our financial statements).
In January 2001, we also recorded a charge of $5 million due to the adoption of
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities."
Recent Developments
Missouri Electric Rate Case
From July 1, 1995 through June 30, 2001, we operated under experimental
alternative regulation plans in Missouri that provided for the sharing of
earnings with customers if our regulatory return on equity exceeded defined
threshold levels. After our experimental alternative regulation plan for our
Missouri retail electric customers expired, the Missouri Public Service
Commission (MoPSC) Staff filed an excess earnings complaint against us with the
MoPSC in July 2001. In March 2002, the MoPSC Staff filed a recommendation that
we reduce our annual Missouri electric revenues by $246 million to $285 million.
The MoPSC Staff's recommendation was based on a return to traditional cost of
service ratemaking, a lowered return on equity, a reduction in our depreciation
rates and other cost of service adjustments. In May 2002, we filed testimony
supporting a rate increase of at least $150 million and proposed a new
alternative regulation plan that included a rate decrease.
On July 16, 2002, AmerenUE, the MoPSC Staff, and all of the other parties
to the proceeding submitted to the MoPSC a stipulation and agreement resolving
this case. On July 24, 2002, the MoPSC held a hearing on the stipulation and
agreement. On July 25, 2002, the MoPSC approved the stipulation and agreement,
and on August 4, 2002, it became effective. The stipulation and agreement
includes the following principal features:
o the phase-in of $110 million of electric rate reductions through April
2004, $50 million of which is retroactively effective as of April 1,
2002, $30 million of which will become effective on April 1, 2003, and
$30 million of which will become effective on April 1, 2004,
o a rate moratorium providing for no requests for changes in our
electric rates as established by the stipulation and agreement before
January 1, 2006 and no resulting changes in rates before June 30,
2006, subject to certain statutory and other exceptions,
o a commitment to contribute, as early as September 2002, $14 million to
programs for low income energy assistance and weatherization,
promotion of energy efficiency and economic development in our service
territory, with additional payments of $3 million made annually on
June 30, 2003 through June 30, 2006,
o a commitment to make $2.25 billion to $2.75 billion in critical energy
infrastructure investments from January 1, 2002 through June 30, 2006,
including, among other things, the addition of more than 700 megawatts
of new generation capacity and the replacement of steam generators at
our nuclear power plant. The 700 megawatts of new generation includes
240 megawatts already added this year and may include the transfer at
book value to us of generation assets from our non-regulated
affiliates. The amount of energy infrastructure investments through
June 2006 described in the stipulation and agreement is consistent
with our previously-disclosed estimate of the construction
expenditures we expect to make over the same time period,
14
o an annual reduction in our depreciation rates by $20 million,
retroactive to April 1, 2002, based on an updated analysis of asset
values, service lives and accumulated depreciation levels, and
o a one-time credit of $40 million to be paid to our Missouri retail
electric customers as early as August 2002 for settlement of the final
sharing period under the alternative regulation plan that expired June
30, 2001. At June 30, 2002, we had accrued $40 million in Current
Liabilities - Other.
In total, the stipulation and agreement is estimated to reduce 2002 net
earnings by $32 million. Net earnings are expected to be reduced in 2002 due to
the rate reduction ($26 million, net of taxes, including $8 million, net of
taxes, in the quarter ended June 30, 2002), the expensing in the quarter ended
June 30, 2002 of the entire obligation to fund certain programs ($15 million,
net of taxes), offset, in part, by the reduction in depreciation expense ($9
million, net of taxes, including $3 million, net of taxes, in the quarter ended
June 30, 2002). Net earnings were reduced by $20 million in the quarter ended
June 30, 2002 due to the stipulation and agreement. We expect earnings to be
reduced by $9 million in the third quarter of 2002 and $3 million in the fourth
quarter of 2002.
CILCORP Acquisition
On April 28, 2002, Ameren entered into an agreement with The AES
Corporation to purchase all of the outstanding stock of CILCORP Inc. CILCORP is
the parent company of Peoria-based Central Illinois Light Company, which
operates as CILCO. Ameren also agreed to acquire AES Medina Valley (No. 4),
L.L.C. which indirectly owns a 40 megawatt, gas-fired electric generation plant.
The total purchase price is approximately $1.4 billion, subject to adjustment
for changes in CILCORP's working capital, and includes the assumption of CILCORP
and AES Medina Valley debt at closing, estimated at approximately $900 million,
with the balance of the purchase price in cash. Ameren expects to finance a
significant portion of the cash component of the purchase price through the
issuance of new common equity.
The purchase will include CILCORP's regulated natural gas and electric
businesses in Illinois serving approximately 205,000 and 200,000 customers,
respectively, of which approximately 150,000 are combination electric and gas
customers. In addition, the purchase includes approximately 1,200 megawatts of
largely coal-fired generating capacity, most of which is expected to be
non-regulated by closing.
Upon completion of the acquisition, expected by March 2003, CILCO will
become an Ameren subsidiary, but will remain a separate utility company,
operating as AmerenCILCO. The transaction is subject to the approval of the
Illinois Commerce Commission, the Securities and Exchange Commission (SEC), the
Federal Energy Regulatory Commission (FERC), the expiration of the waiting
period under the Hart-Scott-Rodino Act, the Federal Communications Commission
and other customary closing conditions.
For the period ended December 31, 2001, CILCORP had revenues of $815
million, operating income of $126 million, and net income from continuing
operations of $28 million, and as of December 31, 2001 had total assets of $1.8
billion.
In April 2002, as a result of our then pending Missouri electric earnings
complaint case and the CILCORP transaction and related assumption of debt,
credit rating agencies placed Ameren Corporation's debt under review for
possible downgrade or negative credit watch. Standard & Poor's placed the
ratings of AmerenUE and AmerenCIPS debt on negative credit watch and placed the
ratings of Generating Company's debt on positive credit watch. However, Standard
& Poor's stated they expect the corporate credit ratings of Ameren and its
subsidiaries to be in the "A" rating category following completion of the
acquisition. Moody's Investor Service stated they envisioned a one notch
downgrade of Ameren's issuer, senior unsecured debt and commercial paper
ratings. Ameren's corporate credit rating is A+ at Standard & Poor's and its
issuer rating is A2 at Moody's, while AmerenUE's corporate credit rating is A+
at Standard & Poor's and its issuer rating is A1 at Moody's. In July, AmerenUE
settled its electric earnings complaint case. The rating agencies have not
changed the assignment of negative watch, review for possible downgrade or
negative outlook to any of the ratings nor have the ratings themselves changed.
Any adverse change in the Ameren companies' ratings may reduce our access to
capital and/or increase the costs of borrowings resulting in a negative impact
on earnings.
15
Electric Operations
The following table represents the favorable (unfavorable) variation for
the three and six-month periods ended June 30, 2002 from the comparable periods
in 2001:
- ----------------------------------------------------------------------------------------------------
Three Months Six Months
- ----------------------------------------------------------------------------------------------------
Operating Revenues:
Effect of abnormal weather (estimate)............ $ 22 $ 10
Growth and other (estimate)...................... 4 22
Rate reductions (13) (13)
Credit to customers.............................. (25) (10)
Interchange revenues............................. (21) 45
- ----------------------------------------------------------------------------------------------------
(33) 54
Fuel and Purchased Power:
Fuel:
Generation..................................... $ (14) $ (6)
Price.......................................... 12 18
Purchased power ................................. 53 (36)
- ----------------------------------------------------------------------------------------------------
51 (24)
- ----------------------------------------------------------------------------------------------------
Change in electric margin $ 18 $ 30
- ----------------------------------------------------------------------------------------------------
Electric margin increased $18 million for the three months and $30 million
for the six months ended June 30, 2002, compared to the prior year periods.
Favorable weather conditions resulted in an increase in weather-sensitive
residential and commercial kilowatt-hour sales of 9% for the three-month period
over the year-ago quarter. Revenues were reduced by $13 million in the three and
six months ended June 30, 2002 due to the settlement of the Missouri electric
rate case. Revenues in 2001 were increased by $25 million in the second quarter,
and $10 million in the first six months, due to a reduction in the accrual for
expected customer sharing credits under the Missouri experimental alternative
regulation plan that expired in June 2001. During the first six months of 2002,
we also experienced growth in electric revenues due to the expansion of our
weather-normalized native load and sales of sulfur dioxide allowances. Although
interchange sales decreased in the quarter, the effect on margin was more than
offset by a resulting decrease in purchased power. Purchased power was also
reduced in the second quarter of 2002 due to the lack of a Callaway nuclear
plant refueling. Another refueling outage at Callaway is scheduled this Fall
which is estimated to reduce net earnings by $14 million through an increase in
purchased power and maintenance expenses. For the six-month period, the impact
on margin of the favorable second quarter weather was somewhat offset by the
milder weather conditions experienced in the first quarter. Total electric
kilowatt-hour sales increased for the six months of 2002, compared to the
year-ago period, primarily due to an increase in interchange sales. Fuel and
purchased power increased to accommodate the larger interchange sales volume. We
realized lower margins on interchange sales compared to the prior year, due to
lower wholesale electricity prices.
The above interchange revenues and fuel and purchased power amounts include
transactions with our affiliates. See Note 3 - "Related Party Transactions" to
our financial statements for further details.
Gas Operations
Our gas revenues and gas margins in second quarter of 2002 were comparable
to the year-ago quarter. Gas margins decreased $4 million for the first six
months of 2002 as compared to the year-ago period as gas revenues decreased $19
million, primarily due to reduced sales of 6% caused by milder winter weather at
the beginning of the year. Reduced gas purchases partially offset the effect of
the reduced sales.
Other Operating Expenses
Other operations related to operating expenses increased $6 million in the
second quarter of 2002 and $5 million in the first six months of 2002, compared
to the year-ago periods, primarily due to higher employee benefit costs related
to the investment performance of pension plan assets and increasing healthcare
costs.
16
Ameren Services and AmerenEnergy provided services to us including wages,
employee benefits, and professional services that were included in Other
Operating Expenses (see Note 3 - "Related Party Transactions" to our financial
statements).
Maintenance expenses decreased $33 million in the second quarter of 2002
and $36 million in the first six months of 2002, compared to the same prior year
periods, primarily due to the lack of a Callaway nuclear plant refueling outage
to date in the current year, along with decreased maintenance at our coal-fired
power plants.
Depreciation and amortization expenses increased $2 in the first six months
of 2002, compared to the year-ago periods, primarily due to an increase in
depreciable property related to investment in our coal power plants, partially
offset by a reduction of depreciation rates based on an updated analysis of
asset values, service lives and accumulated depreciation levels and agreed to in
the stipulation and agreement associated with the Missouri electric rate case.
Income tax expense increased $5 million in the second quarter of 2002 and
$2 million in the first six months of 2002, compared to the same prior year
periods, primarily due to higher pre-tax income.
Other tax expense increased $2 million in the second quarter of 2002 and $4
million in the first six months of 2002, compared to the year-ago periods,
primarily due to higher gross receipts taxes resulting from increased electric
sales.
Other Income and Deductions
Other income and deductions decreased $17 million in the second quarter of
2002 and $21 million in the first six months of 2002, compared to the same
periods last year, primarily due to the commitment to fund certain programs as
part of the settlement of the Missouri electric rate case ($26 million) and
lower intercompany interest earned in the first quarter of 2002 on funds loaned
to the regulated money pool, resulting from lower average intercompany notes
receivable balances. These increases were partially offset by an increase in
earnings from our ownership interest in EEI (second quarter - $10 million;
year-to-date - $11 million) along with increased gains on asset disposals. See
Note 5 - "Miscellaneous, Net" to our financial statements.
Interest
Interest expense decreased $4 million in the second quarter of 2002 and $7
million in the first six months of 2002, compared to the year-ago periods,
primarily due to lower interest rates on our variable rate environmental bonds
and lower interest expense associated with a decreased balance under our nuclear
fuel lease, partially offset by increased short-term intercompany interest as a
result of our borrowings from the money pool in the current year. Amortization
of debt issuance costs and premium/discounts for the three and six months ending
June 30, 2002 of $1 million (2001 - $1 million) and $2 million (2001 - $2
million) were included in interest expense in the income statement.
LIQUIDITY AND CAPITAL RESOURCES
Operating
Our cash flows provided by operating activities increased $18 million to
$243 million in the first six months of 2002, compared to the year-ago period.
Cash flow from operations increased primarily due to increased earnings ($38
million), a decrease in the prior period's liability for electric customer
credits ($45 million), and decreased coal inventories and stored gas ($25
million). Materials and supplies were higher than normal at December 31, 2001,
due to the warm winter and anticipation of a potential coal supply disruption
that ultimately did not occur. The primary use of cash was a reduction of
accounts and wages payable ($90 million).
Our tariff-based gross margins continue to be our principal source of cash
from operating activities. Our diversified retail customer mix of residential,
commercial and industrial classes and a commodity mix of gas and electric
service provide a reasonably predictable source of cash flows. We plan to
utilize short-term debt to support normal operations and other temporary capital
requirements. AmerenUE is authorized by the SEC under PUHCA to have up to $1
billion of short-term unsecured debt instruments outstanding at
17
any one time. Short-term borrowings typically consist of commercial paper with
maturities generally within 1 to 45 days.
As of June 30, 2002, we had several bank credit agreements expiring in 2002
that supported our $430 million commercial paper program, all of which were
unused and available. We also had the ability to borrow up to approximately $425
million from Ameren or from AmerenCIPS, through a regulated money pool agreement
(see Note 3 - "Related Party Transactions" to our financial statements).
In July 2002, Ameren entered into new credit agreements for $400 million in
revolving credit facilities to be used for general corporate purposes, including
support of commercial paper programs. The $400 million in new facilities
includes a $270 million 364-day revolving credit facility and a $130 million
3-year revolving credit facility. The 3-year facility has a $50 million
sub-limit for the issuance of letters of credit. These new credit facilities
replaced our existing $300 million revolving credit facility that was in place
as of June 30, 2002 with a maturity of August 15, 2002. There were no amounts
outstanding under this facility at June 30, 2002. In July 2002, we also did not
renew a $25 million committed line of credit. As a result of these changes, at
July 31, 2002, we had the ability to borrow up to $500 million, all of which was
unused and available, from Ameren through our regulated money pool agreement.
We also have a lease agreement that provides for the financing of nuclear
fuel. At June 30, 2002, the maximum amount that could be financed under the
agreement was $120 million, of which $70 million was utilized.
Our financial agreements include customary default provisions that could
impact the continued availability of credit or result in the acceleration of
repayment. These events include bankruptcy, defaults in payment of other
indebtedness, certain judgments that are not paid or insured, or failure to meet
or maintain covenants. At June 30, 2002, we were in compliance with these
provisions.
Investing
Our net cash used in investing activities was $174 million in the first six
months of 2002 compared to $179 million in the first six months of 2001.
Construction expenditures were incurred primarily for upgrades at our coal power
plants and further construction of combustion turbine generating units. Our
capital expenditures are expected to approximate $500 million in 2002.
As a part of the settlement of the Missouri electric earnings complaint
case (see Note 2 - "Rate and Regulatory Matters" to our financial statements),
we committed to making $2.25 billion to $2.75 billion in infrastructure
investments from January 1, 2002 through June 30, 2006. These investments
include, among other things, the addition of more than 700 megawatts of new
generation capacity and the replacement of steam generators at our Callaway
nuclear power plant. The 700 megawatts of new generation includes 240 megawatts
already added this year and may include the transfer at book value to us of
generation assets from our other non-regulated subsidiaries. The amount of
energy infrastructure investments through June 2006 described in the stipulation
and agreement is consistent with our previously-disclosed estimate of the
construction expenditures we expect to make over the same time period.
Due to expected increased demand and the need to maintain appropriate power
reserve margins, we believe we will need additional generating capacity in the
future. We have an equipment supply agreement in place for the addition of two
combustion turbine generating units with a total installed capacity of 330
megawatts. These units will replace the existing Venice steam plant generating
units which are expected to be retired in 2003. Noncancellable reservation
commitment fees paid of $22 million will be applied to our total cost of these
megawatts pursuant to the agreement.
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 losses
being incurred, which could be material.
18
Financing
Our cash flows used in financing activities were $76 million in the first
six months of 2002 compared to $61 million in the year-ago period. Our principal
financing activities for the current period included the redemption of
short-term debt and the payment of dividends, partially offset by the issuance
of intercompany notes payable.
In May 2002, we filed a shelf registration statement with the SEC on Form
S-3 that allows for 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, as well as for general corporate purposes,
including the repayment of short-term debt incurred to finance construction
expenditures and other working capital needs.
In the ordinary course of business, we evaluate several strategies to
enhance our financial position, earnings, and liquidity. These strategies may
include potential acquisitions, divestitures, opportunities to reduce costs or
increase revenues, and other strategic initiatives in order to increase
shareholder value. We are unable to predict which, if any, of these initiatives
will be executed, as well as the impact these initiatives may have on our future
financial position, results of operations or liquidity.
Electric Industry Restructuring
Illinois
See Note 2 - "Rate and Regulatory Matters" to our financial statements.
Federal - Regional Transmission Organizations
See Note 2 - "Rate and Regulatory Matters" to our financial statements.
ACCOUNTING MATTERS
Critical Accounting Policies
Preparation of the financial statements and related disclosures in
compliance with generally accepted accounting principles requires the
application of appropriate technical accounting rules and guidance, as well as
the use of estimates. Our application of these policies involves judgments
regarding many factors, which, in and of themselves, could materially impact the
financial statements and disclosures. A future change in the assumptions or
judgments applied in determining the following matters, among others, could have
a material impact on future financial results. In the table below, we have
outlined those accounting policies that we believe are most difficult,
subjective or complex:
Accounting Policy Uncertainties Affecting Application
- ----------------- -----------------------------------
Regulatory Mechanisms & Cost Recovery
We defer costs as regulatory assets in o Regulatory environment, external regulatory
accordance with SFAS 71 and make investments decisions and requirements
that we assume we will be able to collect in o Anticipated future regulatory decisions and
future rates. their impact
o Impact of deregulation and competition on
ratemaking process and ability to recover costs
Basis for Judgment
We determine that costs are recoverable based on previous rulings by state
regulatory authorities in jurisdictions where we operate, or other factors
that lead us to believe that cost recovery is probable.
19
Nuclear Plant Decommissioning Costs
In our rates and earnings we assume the o Estimates of future decommissioning costs
Department of Energy will develop a permanent o Availability of facilities for waste disposal
storage site for spent nuclear fuel, the o Approved methods for waste disposal and
Callaway plant will have a useful life of 40 decommissioning
years and estimated costs to dismantle the o Useful lives of nuclear power plants
plant are accurate. See Note 12 to our
financial statements for the year ended
December 31, 2001.
Basis for Judgment
We determine that decommissioning costs are reasonable, or require
adjustment, based on third party decommissioning studies that are completed
every three years, the evaluation of our facilities by our engineers and
the monitoring of industry trends.
Environmental Costs
We accrue for all known environmental o Extent of contamination
contamination where remediation can be o Responsible party determination
reasonably estimated, but some of our o Approved methods for cleanup
operations have existed for over 100 years o Present and future legislation and governmental
and previous contamination may be unknown to regulations and standards
us. o Results of ongoing research and development
regarding environmental impacts
Basis for Judgment
We determine the proper amounts to accrue for environmental contamination
based on internal and third party estimates of clean-up costs in the
context of current remediation regulation standards and available
technology.
Unbilled Revenue
At the end of each period, we estimate, based o Projecting customer energy usage
on expected usage, the amount of revenue to o Estimating impacts of weather and other
record for services that have been provided usage-affecting factors for the unbilled period
to customers, but not billed. This period
can be up to one month.
Basis for Judgment
We determine the proper amount of unbilled revenue to accrue each period
based on the volume of energy delivered as valued by a model of billing
cycles and historical usage rates and growth by customer class for our
service area, as adjusted for the modeled impact of seasonal and weather
variations based on historical results.
Benefit Plan Accounting
Based on actuarial calculations, we accrue o Future rate of return on pension and other plan
costs of providing future employee benefits assets
in accordance with SFAS 87, 106, and 112. o Interest rates used in valuing benefit
See Note 10 to our financial statements for obligations
the year ended December 31, 2001. o Healthcare cost trend rates
Basis for Judgment
We utilize a third party consultant to assist us in evaluating and
recording the proper amount for future employee benefits. Our ultimate
selection of the discount rate, healthcare trend rate and expected rate of
return on pension assets is based on our review of available current,
historical and projected rates, as applicable.
20
Derivative Financial Instruments
We record all derivatives at their fair market o Market conditions in the energy industry, especially
value in accorandce with SFAS 133. The the effects of price volatility on contractual
identification and classification of a commodity commitments
derivative, and the fair value of such o Regulatory and political environments and
derivative must be determined. See Note 4 requirements
to our financial statements for the year o Fair value estimations on longer term contracts
ended December 31, 2001 and Note 4 -
"Derivative Financial Instruments" to our
financial statements.
Basis for Judgment
We determine whether a transaction is a derivative versus a normal purchase
or sale based on historical practice and our intention at the time we enter
a transaction. We utilize actively quoted prices, prices provided by
external sources, and prices based on internal models, and other valuation
methods to determine the fair market value of derivative financial
instruments.
Impact of Future Accounting Pronouncements
See Note 1 - "Summary of Significant Accounting Policies" to our financial
statements.
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk
Market risk represents the risk of changes in value of a physical asset or
financial instrument, derivative or non-derivative, caused by fluctuations in
market variables (e.g. interest rates, etc.). The following discussion of
Ameren's, including AmerenUE's, risk management activities includes
"forward-looking" statements that involve risks and uncertainties. Actual
results could differ materially from those projected in the "forward-looking"
statements. Ameren manages market risks in accordance with established policies,
which may include entering into various derivative transactions. In the normal
course of business, Ameren and our company also face risks that are either
non-financial or non-quantifiable. Such risks principally include business,
legal, and operational risk and are not represented in the following analysis.
Ameren's risk management objective is to optimize its physical generating
assets within prudent risk parameters. Risk management policies are set by a
Risk Management Steering Committee, which is comprised of senior-level Ameren
officers.
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated
with our issuance of both 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, 2002, if interest rates
increased by 1%, our annual interest expense would increase by approximately $8
million and net income would decrease by approximately $5 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.
Fuel Price Risk
100% of the required 2002 supply of coal for our coal power plants has been
acquired at fixed prices. As such, we have minimal coal price risk for 2002. In
addition, approximately 70% of our coal requirements from 2003 through 2006 are
covered by contracts.
21
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 in inventory and under firm
commitment; and
o actual cash outlays for the purchase of these commodities to differ from
anticipated cash outlays.
The derivatives that we use to hedge these risks are dictated by risk
management policies and include forward contracts, futures contracts, options
and swaps. We continually assess our supply and delivery commitment positions
against forward market prices and internally forecast forward prices and modify
our exposure to market, credit and operational risk by entering into various
offsetting transactions. In general, these transactions serve to reduce our
price risk. See Note 4 - "Derivative Financial Instruments" to our financial
statements for more information.
The following summarizes changes in the fair value of all contracts marked
to market during the three and six months ended June 30, 2002:
- ----------------------------------------------------------------------------------------------------------
Three Six
months months
- ----------------------------------------------------------------------------------------------------------
Fair value of contracts at beginning of period, net $ (4) $ (2)
Contracts which were realized or otherwise settled during the period
(5) (5)
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 11 9
- ----------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at June 30, 2002, net $ 2 $ 2
- ----------------------------------------------------------------------------------------------------------
Maturities of contracts as of June 30, 2002 were as follows:
- ----------------------------------------------------------------------------------------------------------
Maturity Maturity in
less than Maturity Maturity excess of 5 Total fair
Sources of fair value 1 year 1-3 years 4-5 years years value (a)
- ----------------------------------------------------------------------------------------------------------
Prices actively quoted - - - - -
Prices provided by other external
sources (b) - - - - -
Prices based on models and other
valuation methods (c) (2) 5 (1) - 2
- ----------------------------------------------------------------------------------------------------------
Total (2) 5 (1) - 2
- ----------------------------------------------------------------------------------------------------------
(a) Nearly 100% of contracts were with investment-grade rated counterparties.
(b) Principally power forward values based on NYMEX prices for over-the-counter contracts.
(c) Principally coal option and sulfur dioxide option values based on a Black-Scholes model that includes
information from external sources and our estimates.
SAFE HARBOR STATEMENT
Statements made in this report which are not based on historical facts, are
"forward-looking" and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
"forward-looking" statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans, strategies, objectives, events, conditions and
financial performance. In connection with the "Safe Harbor" provisions of the
Private Securities Litigation Reform Act of 1995, we are providing this
cautionary statement to identify important factors that could cause actual
results to differ materially from those anticipated. The following factors, in
addition to those discussed elsewhere in this report and in the Annual Report on
Form 10-K for
22
the year ended December 31, 2001, and in subsequent securities filings, could
cause results to differ materially from management expectations as suggested by
such "forward-looking" statements:
o the effects of the stipulation and agreement relating to our 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 FERC-approved Regional Transmission
Organization (RTO), including activities associated with the Midwest
Independent System Operator;
o availability and future market prices for fuel and purchased power,
electricity, and natural gas, including the use of financial and derivative
instruments and volatility of changes in market prices;
o average rates for electricity in the Midwest;
o business and economic conditions;
o the impact of the adoption of new accounting standards;
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 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 benefits costs;
o competition from other generating facilities including new facilities that
may be developed in the future;
o disruptions of the capital markets or other events making AmerenUE's access
to necessary capital more difficult or costly;
o cost and availability of transmission capacity for the energy generated by
our generating facilities or required to satisfy our energy sales; and
o legal and administrative proceedings.
23
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
Reference is made to Item 3. Legal Proceedings in Part I of our Form 10-K
for the year-ended December 31, 2001 and to Item 1. Legal Proceedings in Part II
of our Form 10-Q for the quarterly period ended March 31, 2002 for a discussion
of a number of lawsuits that name our affiliate, Central Illinois Public Service
Company operating as AmerenCIPS, 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, 2002, thirty-four 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, Illinois, involve a large
number of total defendants and seek unspecified damages in excess of $50,000,
which, if proved, typically would be shared among the named defendants. Also
since our first quarter Form 10-Q filing, a settlement has been reached in one
lawsuit for a monetary amount not material to the Ameren companies and in one
case, the Ameren companies have been voluntarily dismissed.
To date, a total of seventy-six asbestos-related lawsuits have been filed
against the Ameren companies, of which sixty-two are pending, ten have been
settled and four have been dismissed. We believe that the final disposition of
these proceedings will not have a material adverse effect on our financial
position, results of operations or liquidity.
ITEM 4. Submission of Matters to a Vote of Security Holders
At our annual meeting of stockholders held on April 23, 2002, the following
matter was presented to the meeting for a vote and the results of such voting
are as follows:
Election of Directors.
Non-Voted
Name For Withheld Brokers
- ---- --- -------- ---------
Paul A. Agathen................... 102,522,452 86,475 0
Warner L. Baxter.................. 102,522,452 86,475 0
Charles W. Mueller................ 102,522,335 86,592 0
Gary L. Rainwater................. 102,522,452 86,475 0
Thomas R. Voss.................... 102,521,846 87,081 0
ITEM 5. Other Information
Any stockholder proposal intended for inclusion in the proxy material for
our 2003 annual meeting of stockholders must be received by us by November 30,
2002.
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 first anniversary of the preceding
year's annual meeting. For our 2003 annual meeting of stockholders, written
notice of any in-person stockholder proposal or director nomination must be
received no later than February 22, 2003 or earlier than January 23, 2003.
24
The Audit Committee of the Board of Directors of Ameren has approved our
independent accountants, PriceWaterhouseCoopers, to perform the following audit
and non-audit services:
o Audits required by the federal, state or local government rules
o Audits of employee pension and benefits plans
o Income tax accounting and consulting projects
o Comfort letters and consents required to complete SEC filings and
issue securities
o Consultation on responses to accounting inquiries by regulatory or
other bodies
o Audit of AmerenEnergy earnings before interest and taxes statement
o Review of stock transfer agent and registrar internal controls
o Review of risk management internal controls
o Consultation on the accounting for corporate events and transactions
o Assistance with preparation of testimony for regulatory filings
ITEM 6. Exhibits and Reports on Form 8-K
(a)(i) Exhibits.
99.1 - Certificate of Chief Executive Officer required by
Section 906 of the Sarbanes-Oxley Act of 2002 (not
filed as a part of this Report on Form 10-Q).
99.2 - Certificate of Chief Financial Officer required by
Section 906 of the Sarbanes-Oxley Act of 2002 (not
filed as a part of this Report on Form 10-Q).
(a)(ii) Exhibits Incorporated by Reference.
10.1 - Memorandum of Understanding dated May 24, 2002
between Ameren Services Company, as agent for
AmerenUE and AmerenCIPS, and the Midwest Independent
Transmission System Operator, Inc. (MISO) (June 30,
2002 Ameren Corporation Form 10-Q, Exhibit 10.1).
10.2 - Participation Agreement dated as of July 3, 2002 by
and among MISO, Ameren Services Company as agent for
AmerenUE and AmerenCIPS, FirstEnergy Corporation on
behalf of American Transmission Systems,
Incorporated, Northern Indiana Public Service Company
and National Grid (June 30, 2002 Ameren Corporation
Form 10-Q, Exhibit 10.2).
99.3 - Stipulation and Agreement dated July 15, 2002 in
Missouri Public Service Commission (MoPSC) Case No.
EC-2002-1 (earnings complaint case against AmerenUE)
(File Nos. 333-87506 and 333-87506-01, Exhibit 99.1).
(b) Reports on Form 8-K. AmerenUE filed reports on Form 8-K as
follows: (i) dated May 28, 2002 relating to the decision of
AmerenCIPS and AmerenUE to rejoin the MISO; (ii) dated July 12,
2002 incorporating a press release stating that an agreement in
principle had been reached in the earnings complaint case filed
by the MoPSC staff against AmerenUE; (iii) dated July 16, 2002
incorporating a press release outlining the details of the
settlement reached in the MoPSC earnings complaint case; and
(iv) dated July 25, 2002 incorporating a press release stating
that the MoPSC had approved the settlement reached in the
earnings complaint case.
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 Ameren Energy Generating Company on Forms 8-K, 10-Q
and 10-K are on file with the SEC under the File Number
333-56594.
25
SIGNATURES
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
Controller
(Principal Accounting Officer)
Date: August 14, 2002
26
Exhibit 99.1
CERTIFICATE
furnished under
Section 906 of the Sarbanes-Oxley Act of 2002.
I, Charles W. Mueller, chief executive officer of Union Electric Company,
hereby certify that to the best of my knowledge, the accompanying Report of
Union Electric Company on Form 10-Q for the quarter ended June 30, 2002 fully
complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 and that information contained in such Report fairly
presents, in all material respects, the financial condition and results of
operations of Union Electric Company.
/s/ Charles W. Mueller
---------------------------------
Charles W. Mueller
Chief Executive Officer
Date: August 14, 2002
Exhibit 99.2
CERTIFICATE
furnished under
Section 906 of the Sarbanes-Oxley Act of 2002.
I, Warner L. Baxter, chief financial officer of Union Electric Company,
hereby certify that to the best of my knowledge, the accompanying Report of
Union Electric Company on Form 10-Q for the quarter ended June 30, 2002 fully
complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 and that information contained in such Report fairly
presents, in all material respects, the financial condition and results of
operations of Union Electric Company.
/s/ Warner L. Baxter
----------------------------------
Warner L. Baxter
Chief Financial Officer
Date: August 14, 2002