UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended September 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 Union Electric Company's common stock as of
November 12, 2002: Common Stock, $5 par value, held by Ameren Corporation
(parent company of registrant) - 102,123,834
UNION ELECTRIC COMPANY
INDEX
Page
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PART I. Financial Information
ITEM 1. Financial Statements (Unaudited)
Balance Sheet at September 30, 2002 and December 31, 2001..... 2
Statement of Income for the three and nine months ended
September 30, 2002 and 2001................................. 3
Statement of Cash Flows for the nine months ended
September 30, 2002 and 2001................................. 4
Statement of Common Stockholder's Equity for the three and
nine months ended September 30, 2002 and 2001............... 5
Notes to Financial Statements................................. 6
ITEM 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................... 15
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.... 25
ITEM 4. Controls and Procedures....................................... 26
PART II. Other Information
ITEM 1. Legal Proceedings............................................. 28
ITEM 5. Other Information............................................. 28
ITEM 6. Exhibits and Reports on Form 8-K.............................. 28
SIGNATURE............................................................... 29
CERTIFICATIONS.......................................................... 29
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 Item 2. "Management's Discussion and Analysis of Financial
Condition and Results of Operations," under the heading "Safe Harbor Statement."
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
BALANCE SHEET
(Unaudited, in millions, except per share amounts)
September 30, December 31,
2002 2001
------------- ------------
ASSETS:
Property and plant, at original cost:
Electric $ 10,222 $ 9,828
Gas 263 252
Other 37 37
------------ -----------
10,522 10,117
Less accumulated depreciation and amortization 4,978 4,802
------------ -----------
5,544 5,315
Construction work in progress:
Nuclear fuel in process 124 97
Other 207 298
------------ -----------
Total property and plant, net 5,875 5,710
------------ -----------
Investments and other assets:
Nuclear decommissioning trust fund 162 187
Other 87 75
------------ -----------
Total investments and other assets 249 262
------------ -----------
Current assets:
Cash and cash equivalents 13 15
Accounts receivable - trade (less allowance for doubtful
accounts of $6 and $7, respectively) 223 144
Unbilled revenue 98 90
Other accounts and notes receivable 27 73
Intercompany notes receivable - 84
Materials and supplies, at average cost -
Fossil fuel 73 71
Other 90 85
Other 25 16
------------ -----------
Total current assets 549 578
------------ -----------
Regulatory assets:
Deferred income taxes 552 604
Other 131 134
------------ -----------
Total regulatory assets 683 738
------------ -----------
Total Assets $ 7,356 $ 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 1,574 1,440
Accumulated other comprehensive income 4 1
------------ -----------
Total common stockholder's equity 2,791 2,654
------------ -----------
Preferred stock not subject to mandatory redemption 114 155
Long-term debt 1,574 1,599
------------ -----------
Total capitalization 4,479 4,408
------------ -----------
Current liabilities:
Current maturities of long-term debt 195 92
Short-term debt - 186
Intercompany notes payable 109 -
Accounts and wages payable 136 305
Accumulated deferred income taxes 3 35
Taxes accrued 311 104
Other 126 128
------------ -----------
Total current liabilities 880 850
------------ -----------
Accumulated deferred income taxes 1,315 1,326
Accumulated deferred investment tax credits 124 129
Regulatory liabilities 130 137
Other deferred credits and liabilities 428 438
------------ -----------
Total Capital and Liabilities $ 7,356 $ 7,288
============ ===========
See Notes to Financial Statements.
2
UNION ELECTRIC COMPANY
STATEMENT OF INCOME
(Unaudited, in millions)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ---------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------
OPERATING REVENUES:
Electric $ 882 $ 1,027 $ 2,229 $ 2,389
Gas 12 20 80 107
------------- ------------- ------------- -------------
Total operating revenues 894 1,047 2,309 2,496
------------- ------------- ------------- -------------
OPERATING EXPENSES:
Operations
Fuel and purchased power 198 372 633 852
Gas 7 7 49 64
Other 142 125 410 388
------------- ------------- ------------- -------------
347 504 1,092 1,304
Maintenance 59 55 182 214
Depreciation and amortization 70 70 211 209
Income taxes 120 134 211 213
Other taxes 67 63 174 166
------------- ------------- ------------- -------------
Total operating expenses 663 826 1,870 2,106
------------- ------------- ------------- -------------
OPERATING INCOME 231 221 439 390
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction 1 4 3 8
Miscellaneous, net -
Miscellaneous income 1 8 24 25
Miscellaneous expense (1) (2) (32) (9)
Income taxes - (1) 8 (2)
------------- ------------- ------------- -------------
Total other income and (deductions) 1 9 3 22
------------- ------------- ------------- -------------
INTEREST CHARGES:
Interest 28 28 82 89
Allowance for borrowed funds used during construction (2) (2) (4) (6)
------------- ------------- ------------- -------------
Net interest charges 26 26 78 83
------------- ------------- ------------- -------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 206 204 364 329
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES - - - (5)
------------- ------------- ------------- -------------
NET INCOME 206 204 364 324
PREFERRED STOCK DIVIDENDS 2 3 6 7
------------- ------------- ------------- -------------
NET INCOME AFTER PREFERRED STOCK DIVIDENDS $ 204 $ 201 $ 358 $ 317
============= ============= ============= =============
See Notes to Financial Statements.
3
UNION ELECTRIC COMPANY
STATEMENT OF CASH FLOWS
(Unaudited, in millions)
Nine Months Ended
September 30,
--------- ---------
2002 2001
--------- ---------
Cash Flows From Operating:
Net income $ 364 $ 324
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting principle - 5
Depreciation and amortization 211 209
Amortization of nuclear fuel 25 21
Amortization of debt issuance costs and premium/discounts 3 2
Allowance for funds used during construction (7) (14)
Deferred income taxes, net 7 17
Deferred investment tax credits, net (5) (2)
Other 3 (1)
Changes in assets and liabilities:
Receivables, net (41) (81)
Materials and supplies (7) (27)
Accounts and wages payable (169) (82)
Taxes accrued 207 226
Assets, other (14) 11
Liabilities, other (18) (53)
--------- ---------
Net cash provided by operating activities 559 555
--------- ---------
Cash Flows From Investing:
Construction expenditures (357) (409)
Allowance for funds used during construction 7 14
Nuclear fuel expenditures (25) (15)
Intercompany notes receivable 84 165
--------- ---------
Net cash used in investing activities (291) (245)
--------- ---------
Cash Flows From Financing:
Dividends on common stock (224) (215)
Dividends on preferred stock (6) (7)
Capital issuance costs (1) -
Redemptions:
Nuclear fuel lease - (64)
Short-term debt (186) -
Long-term debt (125) -
Preferred stock (41) -
Issuances:
Nuclear fuel lease 31 3
Long-term debt 173 11
Intercompany notes payable 109 -
--------- ---------
Net cash used in financing activities (270) (272)
--------- ---------
Net change in cash and cash equivalents (2) 38
Cash and cash equivalents at beginning of year 15 20
--------- ---------
Cash and cash equivalents at end of period $ 13 $ 58
========= =========
Cash paid during the periods:
Interest $ 70 $ 73
Income taxes, net 62 41
See Notes to Financial Statements.
4
UNION ELECTRIC COMPANY
STATEMENT OF COMMON STOCKHOLDER'S EQUITY
(Unaudited, in millions)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------- ---------------------------
2002 2001 2002 2001
------------- ------------ ------------ -----------
Common stock $ 511 $ 511 $ 511 $ 511
Other paid-in capital 702 702 702 702
Retained earnings
Beginning balance 1,442 1,333 1,440 1,358
Net income 206 204 364 324
Common stock dividends (72) (142) (224) (283)
Preferred stock dividends (2) (3) (6) (7)
----------- ----------- ----------- -----------
1,574 1,392 1,574 1,392
----------- ----------- ----------- -----------
Accumulated other comprehensive income
Beginning balance 1 (4) 1 -
Change in current period (see below) 3 2 3 (2)
----------- ----------- ----------- -----------
4 (2) 4 (2)
----------- ----------- ----------- -----------
Total common stockholder's equity $ 2,791 $ 2,603 $ 2,791 $ 2,603
=========== =========== =========== ===========
Comprehensive income, net of taxes
Net income $ 206 $ 204 $ 364 $ 324
Unrealized net gain/(loss) on derivative hedging instruments
(net of income taxes of $2, $1, $3 and $-, respectively) 2 1 4 (1)
Reclassification adjustments for gains/(losses) included in net income
(net of income taxes of $ -, $1, $(1) and $4, respectively) 1 1 (1) 7
Cumulative effect of accounting change, net of income taxes of $(5) - - - (8)
----------- ----------- ----------- ------------
Total comprehensive income, net of taxes $ 209 $ 206 $ 367 $ 322
=========== =========== =========== ============
See Notes to Financial Statements.
5
UNION ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
September 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 and in some cases our agents, AmerenEnergy, Inc. (AmerenEnergy)
and Ameren Energy Fuels and Services Company. All tabular dollar amounts are in
millions, unless otherwise indicated.
Accounting Changes and Other Matters
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 7 -
"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 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 No. 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.
In June 2002, the Financial Accounting Standards Board (FASB) issued SFAS
No. 146, "Accounting for Costs Associated with Exit or Disposal Activities."
SFAS 146 requires an entity to recognize and measure at fair value a liability
for a cost associated with an exit or disposal activity in the period in which
the liability is incurred and nullifies Emerging Issues Task Force (EITF) Issue
No. 94-3, "Liability
6
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (Including Certain Costs Incurred in a Restructuring)." SFAS 146 is
effective for exit or disposal activities that are initiated after December 31,
2002.
During the third quarter ended September 30, 2002, we adopted the
provisions of EITF Issue 02-3, "Accounting for 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 the third quarter of 2002, 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 meant that revenues were recorded for the notional amount of the
power sale contracts with a corresponding charge to income for the costs of the
energy that was generated, or for the notional amount of a purchased power
contract. We now report all contracts within our power risk management program
that have been purchased in anticipation of future price changes on a net basis
as a component of revenues in the income statement. We have also applied this
guidance to all prior periods which had no impact on previously reported
earnings or stockholder's equity. The following table summarizes the impact of
applying the EITF Issue 02-3 on electric operating revenues for the three and
nine month periods ended September 30, 2002:
- --------------------------------------------------------------------------------
Three Months Nine Months
- --------------------------------------------------------------------------------
2002 2001 2002 2001
---- ---- ---- ----
Previously reported gross operating
revenues $958 $1,034 $2,374 $2,396
Costs reclassified 76 7 145 7
- --------------------------------------------------------------------------------
Net operating revenues reported in the
income statement $882 $1,027 $2,229 $2,389
- --------------------------------------------------------------------------------
In October 2002, the EITF reached a consensus to rescind EITF Issue No.
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." The effective date for the full rescission of Issue 98-10 will be
for fiscal periods beginning after December 15, 2002. In addition, the EITF
reached a consensus in October 2002 that all SFAS 133 trading derivatives
(subsequent to the rescission of Issue 98-10) should be shown net in the income
statement whether or not physically settled. This consensus would apply to all
energy and non-energy related trading derivatives that meet the definition of a
derivative pursuant to SFAS 133. The FASB staff indicated that it would attempt
to address, through the October EITF meeting minutes process the effective date
and transition provisions relating to this consensus. The rescission of EITF
98-10 and the related transition guidance could result in additional netting of
certain energy contracts beyond the netting required by EITF 02-3 discussed
above and have the effect of lowering our reported revenues and costs with no
impact on earnings. We are evaluating the impact of this consensus on our
financial statements.
Interchange Revenues
Interchange revenues included in Operating Revenues - Electric were $100
million for the three months ended September 30, 2002 (2001 - $228 million) and
$400 million for the nine months ended September 30, 2002 (2001 - $552 million).
Purchased Power
Purchased power included in Operating Expenses - Operations - Fuel and
Purchased Power was $99 million for the three months ended September 30, 2002
(2001 - $274 million) and $376 million for the nine months ended September 30,
2002 (2001 - $584 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 and
nine months ended September 30, 2002 were $36 million (2001 - $34 million) and
$85 million (2001 - $80 million), respectively. Excise taxes applicable to
Illinois electric customer bills are imposed on the consumer and are recorded as
tax collections payable.
7
Employee Benefit Plans
Ameren Corporation, our parent company, made cash contributions totaling
$15 million to Ameren's defined benefit retirement plans during the third
quarter of 2002, and Ameren expects to make additional cash contributions to the
plans totaling approximately $15 million in the fourth quarter of 2002. Our
share of the cash contribution made in the third quarter of 2002 was
approximately $9 million, and we expect our share of the cash contribution that
may be made in the fourth quarter of 2002 will be approximately $9 million.
Future funding plans will be evaluated at the end of 2002. Based on the
performance of plan assets through September 30, 2002, Ameren expects to be
required under the Employee Retirement Income Security Act of 1974 to fund $25
million to $50 million in 2004 and $150 million to $200 million in 2005 in order
to maintain minimum funding levels. We expect our share of the funding to be
between $14 million to $28 million, and $85 million to $113 million for 2004 and
2005, respectively plus our share related to employees of our affiliate, Ameren
Services Company. These amounts are estimates and may change based on actual
stock market performance, changes in interest rates, any plan funding in 2002 or
2003 and finalization of actuarial assumptions. In addition, we expect at
December 31, 2002, to be required to record a minimum pension liability that
would result in a charge to OCI in stockholder's equity. The amount of the
charge is expected to result in a less than one percent change in debt to total
capitalization ratios.
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 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 was 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, as well as the proposed transfer at net
book value to us of approximately 400 to 500 megawatts of generation assets
from our non-regulated generation affiliate, AmerenEnergy Generating
Company (Generating Company), which is subject to receipt of necessary
regulatory approvals and is expected to be completed in the second quarter
of 2003. 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,
8
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, which was accrued during the plan period.
The entire amount was paid to our Missouri retail electric customers in the
third quarter 2002 for settlement of the final sharing period under the
alternative regulation plan that expired June 30, 2001.
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), 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). Net earnings were reduced due to the
stipulation and agreement by $11 million in the quarter ended September 30, 2002
and by $20 million in the quarter ended June 30, 2002.
In order to satisfy our regulatory load requirements for 2001, we
purchased, under a one-year contract (the 2001 Marketing Company - AmerenUE
agreement), 450 megawatts of capacity and energy from our affiliate,
AmerenEnergy Marketing Company (Marketing Company). 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 (the 2002 Marketing Company
- - AmerenUE agreement) with Marketing Company for the purchase of 200 megawatts
of capacity and energy. 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 Generating Company, in the context of
the 2001 Marketing Company - AmerenUE agreement and requested that the SEC find
that such relationship violates Section 32(k) of the Public Utility Holding
Company Act of 1935 (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 have asserted 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. In its SEC
complaint, 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. While the SEC is still investigating
these matters, the MoPSC and AmerenUE have tentatively reached agreement for
resolving these disputes. The tentative agreement requires us to not enter into
any new contracts to purchase wholesale electric energy from any Ameren
affiliate that is an exempt wholesale generator without first obtaining, on a
timely basis, the determinations required of the MoPSC that are specified in
Section 32(k) of PUHCA. However, this commitment does not prevent us from
completing the purchases contemplated by the 2001 and 2002 Marketing
Company-AmerenUE agreements and making short term energy purchases (less than 90
days) from an Ameren affiliate, without prior MoPSC determination, to prevent or
alleviate system emergencies. As part of the tentative agreement, the MoPSC has
agreed to terminate its SEC complaints.
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. In October 2002,
Marketing Company and the FERC Staff jointly reported to the FERC that they have
negotiated a settlement in principle of the issues that had been set for
hearing, and that they both expect that the settlement will be uncontested.
Other than a slight modification to the procedures for obtaining a broker's
quote to establish off-peak energy prices under the agreement, the settlement in
principle will have no impact on the agreement's price, terms and conditions.
The settlement in principle also establishes guidelines for us to follow when
conducting future requests for proposals for the purpose of pursuing long term
power purchases. Until the SEC and the FERC issue final orders in these
proceedings, management is unable to predict their ultimate impact on our future
financial position, results of operations or liquidity.
Illinois Electric
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
9
competition into the retail supply of electric energy in Illinois. Illinois
residential customers were offered choice in suppliers beginning on May 1, 2002.
Industrial and commercial customers were previously offered this choice.
The original 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.
In October 2002, we and our Illinois-based utility affiliate, Central
Illinois Public Service Company, operating as Ameren CIPS, filed with the
Illinois Commerce Commission (ICC) a proposal to suspend collection of
transition charges associated with the Illinois Law for the period commencing
June 2003 until at least June 2005. The Illinois Law allows a utility to collect
transition charges from customers that elect to move from bundled retail rates
to market-based rates. Utilities have the right to collect transition charges
throughout the transition period that ends January 1, 2007. The suspension of
collection of transition charges is not expected to have a material impact on
us.
Federal - Electric Transmission
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 and AmerenCIPS, 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 (Midwest ISO) 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 Midwest ISO 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 Midwest ISO to
discuss how the Alliance RTO business model could be accommodated within the
Midwest ISO. On April 25, 2002, after the Alliance RTO and Midwest ISO 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 Midwest ISO 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 Midwest ISO at incremental
cost rather than Midwest ISO's full tariff rates. The FERC also ordered the
Midwest ISO to return the exit fees paid by us and AmerenCIPS to leave the
Midwest ISO, provided we and AmerenCIPS return to the Midwest ISO and agree to
pay their proportional share of the startup and ongoing operational expenses of
the Midwest ISO. 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 AmerenCIPS have made filings with
the FERC indicating that we would return to the Midwest ISO through a new
independent transmission company, GridAmerica LLC, that was agreed to be formed
by us and AmerenCIPS, along with subsidiaries of FirstEnergy Corporation and
NiSource Inc. If the FERC approves the definitive agreements establishing
GridAmerica, a subsidiary of National Grid will serve as the managing member of
GridAmerica and will manage the transmission assets of the three companies and
participate in the Midwest ISO on behalf of GridAmerica. Other Alliance RTO
companies announced their intentions to join the PJM Interconnection LLC (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 Midwest ISO 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 Midwest ISO 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
Midwest ISO immediately begin a process to address the reliability and
rate-barrier issues raised by the Ameren companies and other market participants
in previous filings.
10
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 Midwest ISO, 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 Midwest ISO, or the impact that
on-going RTO developments will have on our financial condition, results of
operation or liquidity.
On July 31, 2002, the FERC issued its standard market design notice of
proposed rulemaking (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. We are currently
evaluating the NOPR and its possible impact on operations and expect to file
comments on the NOPR with the FERC in November 2002. Until FERC issues a final
rule, management is unable to predict the ultimate impact on our future
financial position, results of operations or liquidity.
NOTE 3 - Related Party Transactions
AmerenUE has transactions in the normal course of business with its parent,
Ameren Corporation, and Ameren's 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 $36 million for the three months ended September
30, 2002 (2001 - $78 million) and $87 million for the nine months ended
September 30, 2002 (2001 - $122 million). Intercompany power sales totaled $21
million for the three months ended September 30, 2002 (2001 - $17 million) and
$58 million for the nine months ended September 30, 2002 (2001 - $57 million).
Support services provided by our affiliates, Ameren Services and
AmerenEnergy, including wages, employee benefits and professional services are
based on actual costs incurred. For the three months ended September 30, 2002,
Other Operating Expenses provided by Ameren Services and AmerenEnergy totaled
$43 million (2001 - $39 million) and $123 million (2001 - $129 million) for the
nine months ended September 30, 2002.
Intercompany receivables included in Other Accounts and Notes Receivable
were approximately $18 million as of September 30, 2002 (December 31, 2001 - $38
million). Intercompany payables included in Accounts and Wages Payable totaled
approximately $46 million as of September 30, 2002 (December 31, 2001 - $70
million).
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 September 30, 2002 was
our commercial paper program, which was backed by bank credit agreements
totaling $430 million and credit agreements totaling $400 million at Ameren. 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
September 30, 2002, the average interest rate for the regulated money pool was
1.73% (2001 - 3.67%) and for the nine months ended September 30, 2002 was 1.75%
(2001 - 4.51%). As of September 30, 2002, we had the ability to borrow up to
$471 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 and cash balances at Ameren Corporation. At September
30, 2002, we had outstanding intercompany payables of $109 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.
11
In July 2002, Ameren Corporation 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. These new credit
facilities support our ability to borrow through the regulated money pool. The
$400million 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. At September 30, 2002, all of such borrowing capacity under these new
facilities was available.
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 September 30, 2002, we were in compliance with these
provisions.
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 in the value 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.
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 power, again within risk management
guidelines, in anticipation of power requirement and 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 net settled with the counterparty. See Note 1 - "Summary of
Significant Accounting Policies."
As of September 30, 2002, we recorded the fair value of derivative
financial instrument assets of $9 million in Other Assets and the fair value of
derivative financial instrument liabilities of $4 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 and nine month periods ended September 30, 2002, the pretax
net loss on power forward derivative instruments, which represented the impact
of discontinued cash flow hedges, the ineffective
12
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 $3 million. The pretax net gain from these transactions for the
same three months in the prior year was $2 million. In the prior year nine-month
period, we recognized a pretax net gain of $9 million.
As of September 30, 2002, we had hedged a portion of the electricity price
exposure for the upcoming twelve-month period. The mark-to-market value
accumulated in OCI for the effective portion of hedges of electricity price
exposure was a net gain of approximately $1 million ($1 million, net of taxes).
We also held three call options for coal with two suppliers. These options
to purchase coal expire October 2003, July 2004 and July 2005. As of September
30, 2002, the mark-to-market gain accumulated in OCI was $6 million ($3 million,
net of taxes). 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, 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,
while the net change in the market value of coal, heating oil and electricity
options is recorded as Operating Expenses - Operations - Fuel and Purchased
Power in the income statement. The net change in the market values of sulfur
dioxide, coal, heating oil, and electricity options was a gain of $1 million ($1
million net of taxes) for the three months ended September 30, 2002 and $4
million ($2 million, net of taxes) for the nine months ended September 30, 2002.
The change in market values in the prior year resulted in losses of $2 million
($1 million, net of taxes) for the three-month period and $6 million ($4
million, net of taxes) for the nine-month period.
NOTE 5 - Debt Financing
In August 2002, we issued $173 million of 5.25% Senior Secured Notes due
September 1, 2012. Interest is payable semi-annually on March 1 and September 1
of each year, beginning March 1, 2003. Net proceeds were $172 million, after
debt discount and underwriters' fees. These senior secured notes are secured by
a related series of our first mortgage bonds until the release date as described
in the senior secured note indenture. Proceeds were used to redeem, in September
2002, our $125 million principal amount of 8.75% first mortgage bonds due
December 1, 2021 at a 4.38% premium and $41 million of our $1.735 series of
preferred stock at par.
NOTE 6 - Miscellaneous, Net
Miscellaneous, net for the three and nine months ended September 30, 2002
and 2001 consisted of the following:
- -----------------------------------------------------------------------------------------------
Three Months Nine Months
- -----------------------------------------------------------------------------------------------
2002 2001 2002 2001
---- ---- ---- ----
Miscellaneous income:
Interest and dividend income $ - $ 1 $ 2 $ 7
Equity in earnings of subsidiary 1 1 13 3
Gain on disposition of property and other assets - - 3 2
Other - 6 6 13
- -----------------------------------------------------------------------------------------------
Total miscellaneous income $ 1 $ 8 $ 24 $ 25
- -----------------------------------------------------------------------------------------------
Miscellaneous expense:
Plant acquisition amortization $ - $ - $ (1) $ (1)
Donations - rate settlement - - (26) -
Other (1) (2) (5) (8)
- ------------------------------------------------------------------------------------------------
Total miscellaneous expense $(1) $ (2) $(32) $ (9)
- ------------------------------------------------------------------------------------------------
13
NOTE 7 - CILCORP Acquisition
On April 28, 2002, Ameren entered into an agreement with The AES
Corporation (AES) to purchase all of the outstanding common stock of CILCORP
Inc. CILCORP is the parent company of Peoria, Illinois-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 payable in
cash. Ameren expects to finance a significant portion of the cash component of
the purchase price through prior and future issuances 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. CILCO's service territory is contiguous to our service territory. In
addition, the purchase includes approximately 1,200 megawatts of largely
coal-fired generating capacity, most of which is expected to be non-regulated in
2003.
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 ICC,
the SEC under PUHCA, the FERC, the Federal Communications Commission, as well as
the expiration of the waiting period under the Hart-Scott-Rodino Antitrust
Improvements Act and other customary closing conditions. Applications to all
applicable regulatory agencies were made and are proceeding through the approval
process. On August 30, 2002, Ameren and AES received from the U.S. Department of
Justice (DOJ), a Request for Additional Information (Second Request) under the
Hart-Scott-Rodino Act pertaining to the CILCORP acquisition. Ameren intends to
respond to the Second Request by the end of November. Under the stock purchase
agreement with AES, Ameren is obligated to resolve any issues raised by the DOJ
in connection with the Hart-Scott-Rodino filing. Although issuance of a Second
Request is not unusual for transactions of this size, it does extend the review
and waiting period under the Act. Ameren does not expect that this extension
will impact the anticipated transaction closing date. In October 2002, Ameren
resolved all outstanding issues related to the CILCORP acquisition with the ICC
Staff and all interveners that filed testimony in the case. The principal issue,
among other things, related to the potential exercise of market power within the
CILCO service territory. To address this issue, Ameren has agreed to invest
approximately $23 million by December 31, 2008 to increase the power import
capability into CILCO's service territory. The parties expect to agree upon a
draft proposed Order for presentation to the ICC in November, which is expected
to issue a final Order by the end of the year.
For the nine-month period ended September 30, 2002, CILCORP had revenues of
$579 million, operating income of $79 million, and net income from continuing
operations of $29 million, and as of September 30, 2002 had total assets of $1.9
billion. For the year 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.
NOTE 8 - Subsequent Event
On November 4, 2002, Ameren announced a voluntary retirement program that
is being offered to approximately 1,000 of its 7,400 employees including
employees providing support functions to us through Ameren Services and
approximately 250 AmerenUE employees. In addition, Ameren announced limits on
its contributions and increased retiree contributions for certain retiree
medical benefit plans and a freeze on wage increases beginning in 2003 for all
management employees, including AmerenUE management employees. While we and
Ameren expect to realize significant long-term savings as a result of this
program, we expect to incur a one-time, after-tax charge in the fourth quarter
of 2002 related to the voluntary retirement program. That charge for Ameren
could range between $30 million and $50 million, based on voluntary retirements
ranging between 300 and 500, respectively. We expect to be allocated a portion
of this charge depending on the amount of retirements within AmerenUE and Ameren
Services. In addition to the voluntary retirement program, we and Ameren may
consider implementing an involuntary severance program if it is determined that
additional positions must be eliminated to achieve optimum organizational
efficiency and effectiveness. Further, we and Ameren will continue to seek other
ways to reduce staffing over the next year to reduce costs and gain efficiencies
in operations.
14
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
rate-regulated operations. Subsidiaries include AmerenEnergy Generating
Company (Generating Company) that operates non rate-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. (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 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 year 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 year
ended December 31, 2001.
When we refer to AmerenUE, our, we or us, we are referring to Union
Electric Company and in some cases our agents, AmerenEnergy and AmerenEnergy
Fuels and Services Company. All tabular dollar amounts are in millions, unless
otherwise indicated.
Our results of operations and financial position are impacted by many
factors, including both controllable and uncontrollable factors. Weather,
economic conditions, and the actions of key customers or competitors can
significantly impact the demand for our services. Our results are also impacted
by seasonal fluctuations caused by winter heating, and summer cooling, demand.
With nearly all of our revenues directly subject to regulation by various state
and federal agencies, decisions by regulators can have a material impact on the
price we charge for our services. We principally utilize coal, nuclear fuel 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 for our electric utility businesses, but do
have gas cost recovery mechanisms in each state for our gas utility businesses.
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.
15
RESULTS OF OPERATIONS
Summary
Our net income increased to $206 million in the third quarter of 2002, from
$204 million in the third quarter of 2001. Net income for the nine months ended
September 30, 2002, was $364 million, an increase of 12% from the first nine
months of 2001. The increases in 2002 were primarily due to favorable weather
conditions (third quarter - $15 million, net of taxes; year to date - $18
million, net of taxes), increased sales of emission credits, including such
sales by EEI (year to date - $12 million, net of taxes), the lack of a Callaway
nuclear plant refueling outage to date in 2002 (year to date - $19 million, net
of taxes) and lower fuel and purchased power costs. These increases were
partially offset by the impact of the settlement of our Missouri electric rate
case (third quarter - $11 million, net of taxes; year to date - $31 million, net
of taxes) (see below), increased employee benefits expenses (third quarter - $3
million, net of taxes; year to date - $8 million, net of taxes), decreased
interchange revenues, increased sales of emission credits in the prior year
(third quarter - $5 million, net of taxes) and a reduction of an accrual in 2001
for expected customer sharing credits under the Missouri electric experimental
alternative regulation plan that expired in June 2001 (year to date - $6
million, net of taxes) (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
2003 Outlook and Voluntary Retirement Plan
See "Liquidity and Capital Resources - Outlook" for a discussion of
expected challenges to net income in 2003 and beyond, along with a voluntary
retirement plan that was offered to approximately 1,000 Ameren employees in
early November 2002 and is expected to result in a fourth quarter 2002 after-tax
charge to Ameren of between $30 million and $50 million.
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 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 was 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
16
plant. The 700 megawatts of new generation includes 240 megawatts already
added this year, as well as the proposed transfer at net book value to us
of approximately 400 to 500 megawatts of generation assets from our
non-regulated generation affiliate, Generating Company, which is subject to
receipt of necessary regulatory approvals and is expected to be completed
in the second quarter of 2003. 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, which was accrued during the plan period.
The entire amount was paid to our Missouri retail electric customers in the
third quarter of 2002 for settlement of the final sharing period under the
alternative regulation plan that expired June 30, 2001.
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), 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). Net earnings were reduced due to the
stipulation and agreement by $11 million in the quarter ended September 30, 2002
and by $20 million in the quarter ended June 30, 2002.
CILCORP Acquisition
On April 28, 2002, Ameren entered into an agreement with The AES
Corporation (AES) to purchase all of the outstanding common stock of CILCORP
Inc. CILCORP is the parent company of Peoria, Illinois-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 payable in
cash. Ameren expects to finance a significant portion of the cash component of
the purchase price through prior and future issuances 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. CILCO's service territory is contiguous to our service territory. In
addition, the purchase includes approximately 1,200 megawatts of largely
coal-fired generating capacity, most of which is expected to be non-regulated in
2003.
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 (ICC), the Securities and Exchange Commission (SEC)
under PUHCA, the Federal Energy Regulatory Commission (FERC), and the Federal
Communications Commission, as well as the expiration of the waiting period under
the Hart-Scott-Rodino Antitrust Improvements Act and other customary closing
conditions. Applications to all applicable regulatory agencies were made and are
proceeding through the approval process. On August 30, 2002, Ameren and AES
received from the U.S. Department of Justice (DOJ), a Request for Additional
Information (Second Request) under the Hart-Scott-Rodino Act pertaining to the
CILCORP acquisition. Ameren intends to respond to the Second Request by the end
of November. Under the stock purchase agreement with AES, Ameren is obligated to
resolve any issues raised by the DOJ in connection with the Hart-Scott-Rodino
filing. Although issuance of a Second Request is not unusual for transactions of
this size, it does extend the review and waiting period under the Act. Ameren
does not expect that this extension will impact the anticipated transaction
closing date. In October 2002, Ameren resolved all outstanding issues related to
the CILCORP acquisition with the ICC Staff and all interveners that filed
testimony in the case. The principal issue, among other things, related to the
potential exercise of market power within the CILCO service territory. To
address this issue, Ameren agreed to invest approximately $23 million by
December 31, 2008 to increase the power import capability into CILCO's service
territory. The parties expect to agree upon a draft proposed Order for
presentation to the ICC in November, which is expected to issue a final Order by
the end of the year.
For the nine-month period ended September 30, 2002, CILCORP had revenues of
$579 million, operating income of $79 million, and net income from continuing
operations of $29 million, and as of June 30, 2002 had total assets of $1.9
billion. For the year ended December 31, 2001, CILCORP had revenues
17
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 it expects 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 it 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 2002, AmerenUE settled
its electric earnings complaint case. Neither Standard & Poor's nor Moody's has
changed the assignment of negative or positive watch, review for possible
downgrade or negative outlook to any of their ratings nor have the ratings
themselves changed. Subsequent to the settlement of the Missouri electric
earnings complaint case, Fitch Ratings reduced AmerenUE's ratings by one notch
(from "AA" to "AA-" in the case of its first mortgage bonds) and changed the
outlook assigned to AmerenUE's ratings from negative to stable. Any adverse
change in the Ameren companies' ratings may reduce their access to capital
and/or increase the costs of borrowings resulting in a negative impact on
earnings. A credit rating is not a recommendation to buy, sell or hold
securities and should be evaluated independently of any other rating. Ratings
are subject to revision or withdrawal at any time by the assigning rating
organization.
Electric Operations
The following table represents the favorable (unfavorable) variations for
the three and nine-month periods ended September 30, 2002 from the comparable
periods in 2001:
- -----------------------------------------------------------------------------------------------
Three Months Nine Months
- -----------------------------------------------------------------------------------------------
Operating Revenues:
Effect of abnormal weather (estimate)............ $ 35 $ 45
Growth and other (estimate)...................... (29) (7)
Rate reductions.................................. (23) (36)
Credit to customers.............................. - (10)
Interchange sales................................ (128) (152)
- -----------------------------------------------------------------------------------------------
(145) (160)
Fuel and Purchased Power:
Fuel:
Generation..................................... $ (7) $ (12)
Price.......................................... 6 23
Purchased power ................................. 175 208
- -----------------------------------------------------------------------------------------------
174 219
- -----------------------------------------------------------------------------------------------
Change in electric margin $ 29 $ 59
- -----------------------------------------------------------------------------------------------
Electric margin increased $29 million for the three months ended September
30, 2002 and $59 million for the nine months ended September 30, 2002, compared
to the same prior year periods. Favorable weather conditions resulted in an
increase in weather-sensitive residential kilowatt-hour sales of 8% for the
quarter and 4% year-to-date and commercial kilowatt-hour sales of 5% for the
quarter and 4% year-to-date compared to prior year periods. However, industrial
kilowatt-hour sales decreased 4% for the quarter and 10% year-to-date compared
to the prior year periods, primarily due to the soft economy. Revenues were
reduced by $23 million for the third quarter of 2002 and $36 million for the
nine months ended September 30, 2002 due to the settlement of the Missouri
electric rate case. Revenues in 2001 were increased by $10 million in the first
nine 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. Decreased interchange revenues and sales were attributable to
lower energy prices and less low-cost generation available for sale, resulting
primarily from increased demand for generation from native load customers.
Purchased power costs decreased in the third quarter primarily due to the lower
interchange sales and lower prices. Purchased power was reduced in the first
nine months of 2002 due to lower interchange sales and the lack of a Callaway
nuclear plant refueling, partially offset by unscheduled coal plant outages.
Another
18
refueling outage at Callaway began in mid-October, is expected to last 35 days
and is estimated to reduce fourth quarter 2002 net earnings by $14 million, net
of taxes.
During the third quarter ended September 30, 2002, we adopted the provision
of Emerging Issues Task Force (EITF) Issue 02-3, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities," that requires
certain energy contracts to be shown on a net basis in the income statement. See
Note 1 - "Summary of Significant Accounting Policies" to the financial
statements. 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 margins decreased $8 million in the third quarter of 2002 as
compared to the same period in 2001 with gas revenues decreasing $8 million, due
to a 20% decrease in sales. The prior year third quarter included the benefit of
the recovery of gas costs from our customers under a purchased gas adjustment
clause. Gas margins decreased $12 million for the first nine months of 2002 as
compared to the same period in 2001 with gas revenues decreasing $27 million,
primarily due to a 7% reduction caused by milder winter weather at the beginning
of the year and the favorable purchased gas adjustment in the prior year.
Other Operating Expenses
Operating Expenses - Operations - Other increased $17 million in the third
quarter of 2002 and $22 million in the first nine 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, increasing healthcare costs
and increased legal expenses related to the Missouri electric rate case that was
settled in July 2002. See "Liquidity and Capital Resources - Outlook" and Item
3. "Equity Price Risk" below for a discussion of our expectations and plans
regarding trends in employee benefit costs.
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 increased $4 million in the third quarter of 2002,
compared to the same prior year period, primarily due to increased expenses in
preparation for the Callaway nuclear plant refueling that began in mid-October
2002. Maintenance expenses decreased $32 million in the first nine months of
2002, compared to the same prior year period, primarily due to the lack of a
Callaway nuclear plant refueling outage in the first nine months of 2002, along
with decreased maintenance at our coal-fired power plants.
Depreciation and amortization expenses remained comparable for the third
quarter compared to same year-ago period. Expenses increased $2 million in the
first nine months of 2002, compared to the year-ago periods, primarily due to
our investment in coal-fired power plants. The increase in 2002 was partially
offset by a reduction in depreciation rates based on an updated analysis of
asset values, service lives and accumulated depreciation levels agreed to in the
stipulation and agreement associated with the Missouri electric rate case (third
quarter - $5 million; year-to-date $10 million).
Income tax expense decreased $15 million in the third quarter of 2002 due
to lower pretax income. Income tax expense decreased $12 million in the first
nine months of 2002 primarily due to the lower effective tax rate. Income taxes
related to our non-regulated operations are recorded in Other Income and
Deductions.
Other tax expense increased $4 million in the third quarter of 2002 and $8
million in the first nine months of 2002, compared to the year-ago periods,
primarily due to higher gross receipts taxes resulting from increased electric
residential and commercial sales.
Other Income and Deductions
Other income and deductions (excluding income taxes) decreased $9 million
in the third quarter of 2002 and $29 million in the first nine 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), 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 and increased
19
coal supply risk management costs. These decreases were partially offset by an
increase in earnings from our ownership interest in EEI primarily resulting from
its sale of emission credits (year-to-date - $10 million) along with increased
gains on asset disposals. See Note 6 - "Miscellaneous, Net" to our financial
statements.
Interest
Interest expense for the third quarter 2002 was flat compared to 2001, but
decreased $7 million in the first nine months of 2002, compared to the year-ago
period, primarily due to lower interest rates on our variable rate environmental
debt obligations 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 nine months ending September 30, 2002 of $1 million (2001 - less than
$1 million) and $3 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 $4 million to
$559 million in the first nine months of 2002 compared to the year-ago period.
Cash provided by operations increased primarily due to higher net income despite
lower rates associated with our Missouri rate case settlement and a decrease in
materials and supplies due to higher than normal amounts at December 31, 2001
due to the warm winter and anticipation of a potential coal supply disruption
that ultimately did not occur which was partially offset by the timing of
payments on accounts payable and accrued taxes including the payments of
customer sharing credits under our now-expired electric alternative regulation
plan.
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 any one time.
Short-term borrowings typically consist of commercial paper with maturities
generally within 1 to 45 days.
As of September 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 $471
million from Ameren, through a regulated money pool agreement. See Note 3 -
"Related Party Transactions" to our financial statements.
In July 2002, Ameren Corporation 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, all of which was
available at September 30, 2002. These new credit facilities support our ability
to borrow through the regulated money pool. 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 $300 million revolving credit facility that was in place as of June
30, 2002.
We also have a lease agreement that provides for the financing of nuclear
fuel. At September 30, 2002, the maximum amount that could be financed under the
agreement was $120 million. At September 30, 2002, $94 million was financed
under the lease.
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 September 30, 2002, we were in compliance with these
provisions.
At September 30, 2002, we did not have any off-balance sheet financing
arrangements.
20
Ameren Corporation made cash contributions totaling $15 million to Ameren's
defined benefit retirement plans during the third quarter of 2002 and expects to
make additional cash contributions to the plans totaling approximately $15
million in the fourth quarter of 2002. Our share of the cash contribution made
in the third quarter of 2002 was approximately $9 million, and we expect our
share of the cash contribution that may be made in the fourth quarter of 2002
will be approximately $9 million. Future funding plans will be evaluated at the
end of 2002. Based on the performance of plan assets through September 30, 2002,
Ameren expects to be required under the Employee Retirement Income Security Act
of 1974 to fund $25 million to $50 million in 2004 and $150 million to $200
million in 2005 in order to maintain minimum funding levels. We expect our share
of the funding to be between $14 million to $28 million, and $85 million to $113
million for 2004 and 2005, respectively plus our share related to employees of
Ameren Services. These amounts are estimates and may change based on actual
stock market performance, changes in interest rates, any plan funding in 2002 or
2003 and finalization of actuarial assumptions. In addition, we expect at
December 31, 2002, to be required to record a minimum pension liability that
would result in a charge to Accumulated Other Comprehensive Income (OCI) in
stockholder's equity. The amount of the charge is expected to result in a less
than one percent change in debt to total capitalization ratios.
Investing
Our net cash used in investing activities was $291 million in the first
nine months of 2002 compared to $245 million in the first nine months of 2001.
Construction expenditures were incurred primarily for upgrades at our coal power
plants and construction of combustion turbine generating units. Our capital
expenditures are expected to approximate $145 million in the fourth quarter of
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, as well as the proposed transfer of 400 to 500
megawatts of combustion turbine units to us from Generating Company. The
transfer which is subject to necessary regulatory approvals, is expected to be
completed in the second quarter of 2003.
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 are expected to replace the existing Venice steam plant
generating units which are expected to be retired by mid-2005. Non-cancelable
reservation commitment fees paid of $22 million will be applied to our total
cost of these two units.
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.
Financing
Our cash flows used in financing activities were $270 million in the first
nine months of 2002 compared to $272 million in the year-ago period. Our
principal financing activities for the current period included the redemptions
of short-term debt, long-term debt and preferred stock and the payment of
dividends, partially offset by the issuance of long-term debt and intercompany
notes payable.
In May 2002, we filed a shelf registration statement with the SEC on Form
S-3 authorizing 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. The SEC declared the registration
statement effective in August 2002.
In August 2002, AmerenUE issued, pursuant to the shelf registration
statement, $173 million of 5.25% Senior Secured Notes due September 1, 2012.
Interest is payable semi-annually on March 1 and September
21
1 of each year, beginning March 1, 2003. Net proceeds were $172 million, after
debt discount and underwriters' fees. These senior secured notes are secured by
a related series of our first mortgage bonds until the release date as described
in the senior secured note indenture. Proceeds were used to redeem, in September
2002, our $125 million principal amount of 8.75% first mortgage bonds due
December 1, 2021 at a 4.38% premium and $41 million of our $1.735 series of
preferred stock at par. We may sell all, or a portion of, the remaining
registered securities under the 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.
Outlook
We currently believe there will be challenges to earnings in 2003 and
beyond due to continued weak energy markets, a soft economy, higher employee
benefit costs and escalating insurance and security costs associated with world
events. These industry-wide trends, coupled with an assumed return to more
normal weather patterns and the impact of our Missouri electric rate case
settlement, are expected to put pressure on earnings in 2003 and beyond. As we
complete our analysis of these challenges as part of our overall budget process,
we will be evaluating several initiatives to enhance revenues and reduce costs
for 2003 and beyond. These initiatives may include the following:
o Actively managing employee headcount
o Modifying employee benefit plans
o Assessing the necessity of certain plant operations and business support
functions
o Reviewing capital expenditure plans
o Other initiatives
On November 4, 2002, Ameren announced a voluntary retirement program that
is being offered to approximately 1,000 of its 7,400 employees including
approximately 250 AmerenUE employees and employees providing support functions
to us through Ameren Services. In addition, Ameren announced limits on its
contributions and increased retiree contributions for certain retiree medical
benefit plans and a freeze on wage increases beginning in 2003 for all
management employees. While we and Ameren expect to realize significant
long-term savings as a result of this program, we expect to incur a one-time,
after-tax charge in the fourth quarter of 2002 related to the program. That
charge for Ameren could range between $30 million and $50 million, based on
voluntary retirements ranging between 300 and 500, respectively. We expect to be
allocated a portion of this charge depending on the amount of retirements within
AmerenUE and Ameren Services. In addition to the voluntary retirement program,
we and Ameren may consider implementing an involuntary severance program if it
is determined that additional positions must be eliminated to achieve optimum
organizational efficiency and effectiveness. Further, we and Ameren will
continue to seek other ways to reduce staffing over the next year to reduce
costs and gain efficiencies in operations.
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 and Regulatory Matters
Illinois
See Note 2 - "Rate and Regulatory Matters" to our financial statements.
Federal - Electric Transmission
See Note 2 - "Rate and Regulatory Matters" to our financial statements.
22
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 their
future rates. 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.
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
23
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 assets
costs of providing future employee benefits o Interest rates used in valuing benefit obligations
in accordance with SFAS 87, 106, and 112. o Healthcare cost trend rates
See Note 10 to our financial statements for
the year ended December 31, 2001.
Basis for Judgment
We utilize a third party consultant to assist us in evaluating and recording the proper amount for future
employee benefits. Our ultimate selection of the discount rate, healthcare trend rate and expected rate of
return on pension assets is based on our review of available current, historical and projected rates, as
applicable.
Derivative Financial Instruments
We record all derivatives at their fair market o Market conditions in the energy industry, especially
value in accordance 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 in this report.
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.
24
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 September 30, 2002, if interest rates
increased by 1%, our annual interest expense would increase by approximately $6
million and net income would decrease by approximately $4 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 and 98% of the required 2003 supply of coal for
our coal power plants has been acquired at fixed prices. As such, we have
minimal coal price risk for the remainder of 2002 and 2003. Approximately 59% of
our coal requirements for 2003 through 2006 are covered by contracts.
Our gas business is not subject to fuel price risk as we have gas cost
recovery mechanisms in both Missouri and Illinois.
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, we believe these transactions serve to
reduce our price risk. See Note 4 - "Derivative Financial Instruments" to our
financial statements for more information.
25
The following summarizes changes in the fair value of all contracts marked
to market during the three and nine months ended September 30, 2002:
- -------------------------------------------------------------------------------------------------------
Three Nine
months months
- -------------------------------------------------------------------------------------------------------
Fair value of contracts at beginning of period, net $ 2 $ (2)
Contracts which were realized or otherwise settled during the period - (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 3 12
- -------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at September 30, 2002, net $ 5 $ 5
=======================================================================================================
Maturities of contracts as of September 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) 1 - - - 1
Prices based on models and other
valuation methods (c) (2) 6 - - 4
- -----------------------------------------------------------------------------------------------------------
Total $ (1) $ 6 - - $ 5
===========================================================================================================
(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 and sulfur dioxide option values based on a Black-Scholes model that includes
information from external sources and our estimates.
Equity Price Risk
We, along with other subsidiaries of Ameren, are a participant in Ameren's
defined benefit plans and postretirement benefit plans and are responsible for
our proportional share of the costs. Ameren's costs of providing
non-contributory defined benefit retirement and postretirement benefit plans are
dependent upon a number of factors, such as the rates of return on plan assets,
discount rate, the rate of increase in health care costs and contributions made
to the plans. The market value of our plan assets has been affected by declines
in the equity market since 2001 and 2000 for the pension and postretirement
plans. As a result, at December 31, 2002, Ameren and its subsidiaries, including
AmerenUE, could be required to recognize an additional minimum pension liability
as prescribed by SFAS No. 87, "Employers' Accounting for Pensions" and SFAS No.
132, "Employers' Disclosures about Pensions and Postretirement Benefits." The
liability would be recorded as a reduction to OCI and would not affect net
income for 2002. The amount of the liability will depend upon asset returns
experienced in 2002, changes in interest rates and Ameren's contributions to the
plan during 2002. The liability recorded and cash contributions to the plans
could be material in future years without a substantial recovery in equity
markets. If the fair value of the plan assets were to grow and exceed the
accumulated benefit obligations in the future, then the recorded liability, if
any, would be reduced and a corresponding amount of OCI would be restored in the
Balance Sheet. See "Liquidity and Capital Resources - Operating" and Note 1 -
"Summary of Significant Accounting Policies" to our financial statements.
ITEM 4. Controls and Procedures
Within the 90 days prior to the date of this report, we carried out an
evaluation, under the supervision and with the participation of our management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13a-14 under the Securities Exchange Act of 1934, as
amended. Based upon that evaluation, the Chief Executive Officer and Chief
Financial Officer concluded that our disclosure controls and procedures are
effective in timely alerting them to material information relating to AmerenUE
required to be included in our periodic SEC filings.
26
There have been no significant changes in our internal controls or in other
factors which could significantly affect internal controls subsequent to the
date we carried out our evaluation.
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 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 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 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 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 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, including changes in returns of
benefit plan assets;
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 Ameren's and our
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.
Given these uncertainties, undue reliance should not be placed on these
forward-looking statements. Except to the extent required by the federal
securities laws, we undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
27
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
Reference is made to Note 11 to the Notes to Financial Statements under
Item 8. "Financial Statements and Supplementary Data" in Part II of our Form
10-K for the year ended December 31, 2001 for a discussion of environmental
proceedings which relate to sites located in Sauget, Illinois. On September 30,
2002, the United States Environmental Protection Agency (EPA) issued a
unilateral administrative order (UAO) with respect to a portion of Sauget Area
2. The EPA has ordered Solutia, Inc., formerly known as Monsanto Chemical
Company, to construct a barrier wall around a former chemical landfill as an
interim remedy to address groundwater contamination. The EPA issued the UAO to
approximately 75 parties whom it considers to be potentially responsible parties
(PRPs) at the Sauget Area 2 site including us. The UAO directs the PRPs to
participate with Solutia, Inc. in performing the work mandated by the UAO. We
believe that the UAO has been improperly directed to us and have submitted a
response to the EPA regarding our good faith defenses to the UAO.
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 10Qs for the quarterly periods ended March 31, 2002 and June 30,
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 June 30, 2002, 29 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 the filing of our Form 10-Q for the quarterly
period ended June 30, 2002, the Ameren companies have been voluntarily dismissed
in two cases.
To date, a total of 107 asbestos-related lawsuits have been filed against
the Ameren companies, of which 91 are pending, 10 have been settled and six 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 5. Other Information
Reference is made to Item 5. "Other Information" in Part II of our Form
10-Q for the quarterly period ended June 30, 2002 for a listing of the audit and
non-audit services that the Auditing Committee of the Ameren Board of Directors
has pre-approved for performance by our independent accountants,
PricewaterhouseCoopers LLP. At its October 2002 meeting, the Auditing Committee
also pre-approved PricewaterhouseCoopers LLP to perform audits of two AmerenUE
coal supply contracts with respect to the handling of prepaid reclamation funds.
Reference is made to Note 11 to the Notes to Financial Statements under
Item 8. "Financial Statements and Supplementary Data" in Part II of our Form
10-K for the year ended December 31, 2001 for a discussion of the Price-Anderson
Act which, as indicated, limits the liability for claims from an incident
involving any licensed U.S. nuclear facility such as AmerenUE's Callaway nuclear
power plant. This federal law expired in August 2002 and renewal legislation is
pending before Congress. Until the Price-Anderson Act is extended, its
provisions continue to apply to existing nuclear plants such as Callaway.
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits.
99.1 - Certificate of Chief Executive Officer required by Section
906 of the Sarbanes-Oxley Act of 2002.
99.2 - Certificate of Chief Financial Officer required by Section
906 of the Sarbanes-Oxley Act of 2002.
28
(b) Reports on Form 8-K. AmerenUE filed reports on Form 8-K as
follows: (i) 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 Missouri Public Service
Commission (MoPSC) staff against AmerenUE; (ii) dated July 16,
2002 incorporating a press release outlining the details of the
settlement reached in the MoPSC earnings complaint case; (iii)
dated July 25, 2002 incorporating a press release stating that
the MoPSC had approved the settlement reached in the earnings
complaint case; and (iv) dated August 22, 2002 reporting
AmerenUE's issuance and sale of $173,000,000 principal amount of
its 5.25% Senior Secured Notes due 2012 and filing as exhibits
certain documents in connection with that offering.
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 File Number 333-56594.
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
Controller
(Principal Accounting Officer)
Date: November 14, 2002
CERTIFICATIONS
I, Charles W. Mueller, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Union Electric
Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
29
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 14, 2002 /s/ Charles W. Mueller
----------------------------
Charles W. Mueller
Chief Executive Officer
I, Warner L. Baxter, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Union Electric
Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
30
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 14, 2002 /s/ Warner L. Baxter
------------------------
Warner L. Baxter
Chief Financial Officer
31
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 September 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: November 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 September 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: November 14, 2002