UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For Quarterly Period Ended March 31, 2002
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For The Transition Period From to
Commission file number 1-2967.
UNION ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Missouri 43-0559760
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1901 Chouteau Avenue, St. Louis, Missouri 63103
(Address of principal executive offices and Zip Code)
Registrant's telephone number,
including area code: (314) 621-3222
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X . No .
------------ ------------
Shares outstanding of each of the registrant's classes of common stock as of May
10, 2002: Common Stock, $5 par value, held by Ameren Corporation (parent company
of registrant) - 102,123,834
UNION ELECTRIC COMPANY
INDEX
Page
----
PART I Financial Information
ITEM 1. Financial Statements
Balance Sheet at March 31, 2002 and December 31, 2001............ 2
Statement of Income for the three months ended
March 31, 2002 and 2001.......................................... 3
Statement of Cash Flows for the three months ended
March 31, 2002 and 2001.......................................... 4
Statement of Common Stockholder's Equity for the three months
ended March 31, 2002 and 2001.................................... 5
Notes to Financial Statements.................................... 6
ITEM 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations........................................ 11
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk....... 17
PART II Other Information
ITEM 1. Legal Proceedings................................................ 21
ITEM 6. Exhibits and Reports on Form 8-K................................. 21
SIGNATURE................................................................... 22
1
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
UNION ELECTRIC COMPANY
BALANCE SHEET
(In Millions, Except Per Share Amounts)
March 31, December 31,
2002 2001
----------- ------------
(Unaudited)
ASSETS:
Property and plant, at original cost:
Electric $ 9,919 $ 9,828
Gas 255 252
Other 37 37
-------- --------
10,211 10,117
Less accumulated depreciation and amortization 4,862 4,802
-------- --------
5,349 5,315
Construction work in progress:
Nuclear fuel in process 102 97
Other 288 298
-------- --------
Total property and plant, net 5,739 5,710
-------- --------
Investments and other assets:
Nuclear decommissioning trust fund 188 187
Other 84 75
-------- --------
Total investments and other assets 272 262
-------- --------
Current assets:
Cash and cash equivalents 12 15
Accounts receivable - trade (less allowance for doubtful
accounts of $8 and $7, respectively) 222 234
Other accounts and notes receivable 30 73
Intercompany notes receivable - 84
Materials and supplies, at average cost -
Fossil fuel 56 71
Other 86 85
Other 13 16
-------- --------
Total current assets 419 578
-------- --------
Regulatory assets:
Deferred income taxes 604 604
Other 131 134
-------- --------
Total regulatory assets 735 738
-------- --------
Total Assets $ 7,165 $ 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 1,413 1,440
Accumulated other comprehensive income (1) 1
-------- --------
Total common stockholder's equity 2,625 2,654
-------- --------
Preferred stock not subject to mandatory redemption 155 155
Long-term debt 1,605 1,599
-------- --------
Total capitalization 4,385 4,408
-------- --------
Current liabilities:
Current maturity of long-term debt 89 92
Short-term debt - 186
Intercompany notes payable 192 -
Accounts and wages payable 135 305
Accumulated deferred income taxes 34 35
Taxes accrued 158 104
Other 126 128
-------- --------
Total current liabilities 734 850
-------- --------
Accumulated deferred income taxes 1,322 1,326
Accumulated deferred investment tax credits 127 129
Regulatory liabilities 137 137
Other deferred credits and liabilities 460 438
-------- --------
Total Capital and Liabilities $ 7,165 $ 7,288
======== ========
See Notes to Financial Statements.
2
UNION ELECTRIC COMPANY
STATEMENT OF INCOME
UNAUDITED
(In Millions)
Three Months Ended
March 31,
-------------------------
2002 2001
OPERATING REVENUES: ---- ----
Electric $ 684 $ 597
Gas 50 69
----- -----
Total operating revenues 734 666
OPERATING EXPENSES:
Operations
Fuel and purchased power 294 219
Gas 32 46
Other 129 130
----- -----
455 395
Maintenance 55 58
Depreciation and amortization 72 69
Income taxes 28 31
Other taxes 52 50
----- -----
Total operating expenses 662 603
----- -----
OPERATING INCOME 72 63
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction 1 1
Miscellaneous, net 3 7
----- -----
Total other income and (deductions) 4 8
INCOME BEFORE INTEREST CHARGES 76 71
INTEREST CHARGES:
Interest 27 30
Allowance for borrowed funds used during construction (2) (2)
----- -----
Net interest charges 25 28
----- -----
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 51 43
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES - (5)
----- -----
NET INCOME 51 38
PREFERRED STOCK DIVIDENDS 2 2
----- -----
NET INCOME AFTER PREFERRED STOCK DIVIDENDS $ 49 $ 36
===== =====
See Notes to Financial Statements.
3
UNION ELECTRIC COMPANY
STATEMENT OF CASH FLOWS
UNAUDITED
(In Millions)
Three Months Ended
March 31,
---------------------
2002 2001
---- ----
Cash Flows From Operating:
Net income $ 51 $ 38
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting principle - 5
Depreciation and amortization 69 65
Amortization of nuclear fuel 7 9
Allowance for funds used during construction (3) (3)
Deferred income taxes, net (4) (6)
Deferred investment tax credits, net (2) (2)
Changes in assets and liabilities:
Receivables, net 55 9
Materials and supplies 14 9
Accounts and wages payable (170) (69)
Taxes accrued 54 56
Other, net 14 18
----- -----
Net cash provided by operating activities 85 129
Cash Flows From Investing:
Construction expenditures (101) (89)
Allowance for funds used during construction 3 3
Nuclear fuel expenditures (5) (8)
Intercompany notes receivable 84 18
----- -----
Net cash used in investing activities (19) (76)
Cash Flows From Financing:
Dividends on common stock (76) (54)
Dividends on preferred stock (2) (2)
Redemptions:
Nuclear fuel lease - (35)
Short-term debt (186) -
Issuances:
Nuclear fuel lease 3 2
Long-term debt - 41
Intercompany notes payable 192 -
----- -----
Net cash used in financing activities (69) (48)
----- -----
Net change in cash and cash equivalents (3) 5
Cash and cash equivalents at beginning of year 15 20
----- -----
Cash and cash equivalents at end of period $ 12 $ 25
===== =====
Cash paid during the periods:
Interest (net of amount capitalized) $ 19 $ 21
Income taxes, net $ 4 $ -
See Notes to Financial Statements.
4
UNION ELECTRIC COMPANY
STATEMENT OF COMMON STOCKHOLDER'S EQUITY
UNAUDITED
(In Millions)
Three Months Ended
March 31,
---------------------
2002 2001
---- ----
Common stock $ 511 $ 511
Other paid-in capital 702 702
Retained earnings
Beginning balance 1,440 1,358
Net income 51 38
Common stock dividends (76) (54)
Preferred stock dividends (2) (2)
------------ ----------
1,413 1,340
Accumulated other comprehensive income
Beginning balance 1 -
Change in current period (2) (2)
------------ ----------
(1) (2)
Total common stockholder's equity $ 2,625 $ 2,551
============ ==========
Comprehensive income, net of taxes
Net income $ 51 $ 38
Unrealized net gain/(loss) on derivative hedging instruments (2) 6
Cumulative effect of accounting change - (8)
------------ ----------
$ 49 $ 36
============ ==========
See Notes to Financial Statements.
5
UNION ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
March 31, 2002
NOTE 1 - Summary of Significant Accounting Policies
Basis of Presentation
Our financial statements reflect all adjustments (which include normal,
recurring adjustments) necessary, in our opinion, for a fair presentation of the
interim results. These statements should be read in conjunction with the
financial statements and the notes thereto included in our 2001 Annual Report on
Form 10-K.
When we refer to AmerenUE, our, we or us, we are referring to Union
Electric Company. All dollar amounts are in millions, unless otherwise
indicated.
Accounting Changes
In January 2001, we adopted Statement of Financial Accounting Standards
(SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities."
The impact of that adoption resulted in a cumulative effect charge of $5 million
after taxes to the income statement, and a cumulative effect adjustment of $8
million after taxes to Accumulated Other Comprehensive Income (OCI), which
reduced common stockholder's equity.
On January 1, 2002, we adopted SFAS No. 141, "Business Combinations," and
SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS 141 requires business
combinations to be accounted for under the purchase method of accounting, which
requires one party in the transaction to be identified as the acquiring
enterprise and for that party to allocate the purchase price to the assets and
liabilities of the acquired enterprise based on fair market value. SFAS 142
requires goodwill and indefinite-lived intangible assets recorded in the
financial statements to be tested for impairment at least annually, rather than
amortized over a fixed period, with impairment losses recorded in the income
statement. SFAS 141 and SFAS 142 did not have any effect on our financial
position, results of operations or liquidity upon adoption.
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 as a result of obligations associated with Callaway
Nuclear Plant decommissioning costs which are being fully recovered in our
rates.
On January 1, 2002 we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." SFAS 144 addresses the financial accounting
and reporting for the impairment or disposal of long-lived assets and supersedes
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of." SFAS 144 retains the guidance related to calculating
and recording impairment losses, but adds guidance on the accounting for
discontinued operations, previously accounted for under Accounting Principles
Board Opinion No. 30. SFAS 144 did not have any effect on our financial
position, results of operations or liquidity upon adoption.
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. At March 31, 2002, we had an accrual representing the
estimated credit
6
that we expect to pay our Missouri electric customers of $40 million for the
plan year ended June 30, 2001. In 2002, the Missouri Public Service Commission
(MoPSC) Staff and the Missouri Office of Public Counsel (OPC) Staff filed
testimony with the MoPSC on this matter. Combined, the MoPSC Staff and OPC Staff
recommend that the credit to customers for the plan year ended June 30, 2001,
should approximate $80 million. The MoPSC is not bound by their
recommendations. To date, a procedural schedule and hearing dates on this matter
have not been established by the MoPSC. At this time, we continue to believe
that our accrual is adequate in all material respects.
Following expiration of the experimental alternative regulation plan on
June 30, 2001, the MoPSC Staff filed an excess earnings complaint against us.
Based upon a January 2002 MoPSC order, on March 1, 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 is based on a return
to traditional cost of service ratemaking, a return on equity ranging from 8.91%
to 9.91%, a reduction in our depreciation rates, and other cost of service
adjustments. The MoPSC is not bound by the Staff's recommendation.
On May 10, 2002, we filed rebuttal testimony in response to the MoPSC
Staff's recommendation. In our testimony, we stated that a return to traditional
cost of service ratemaking would result in an increase in our annual Missouri
electric revenues by approximately $150 million. Our position is based on a
12.5% return on equity, higher depreciation rates and other adjustments.
However, a key component of our testimony is our recommendation that a new
alternative rate regulation plan (Alt Reg Plan) be adopted by the MoPSC. In our
filing, we included a new Alt Reg Plan proposal. Key provisions of the Alt Reg
Plan include the following:
o A three-year plan from July 1, 2002 through June 30, 2005 which would
require us to share earnings over certain regulatory return on equity
(ROE) thresholds for the 12 months ending July 1 through June 30;
o The proposed earnings sharing grid would require us to provide sharing
credits of $17 million if our regulatory ROE is between 10.5% and
12.5%. Additional credits of 55% of our earnings between a regulatory
ROE of 12.5% and 15% would be provided, 90% of earnings between a
regulatory ROE of 15% and 16%, and 100% of any earnings above 16%.
o An immediate one-time credit to customers bills of $15 million;
o An annualized $15 million permanent rate reduction, retroactive to
April 1, 2002;
o An immediate funding of $5 million to a low-income customer assistance
program and $5 million to an economic development program;
o A commitment of $1.5 billion to $1.75 billion in energy infrastructure
investment from January 1, 2002 through June 30, 2005.
Hearings for this case are scheduled to commence in mid-July 2002 and be
completed in early August 2002. A final decision on this matter may not occur
until the fourth quarter of 2002. In the interim, we plan to continue
negotiations with all pertinent parties with the intent to continue with an
incentive regulation plan. We cannot predict the outcome of the MoPSC's decision
in this matter or its impact on our financial statements, results of operations
or liquidity. However, the impact could be material.
In order to satisfy our regulatory load requirements for 2001, we
purchased, through a competitive bidding process, 450 megawatts of capacity and
energy under a one-year contract from our affiliate, Ameren Energy Marketing
Company (Marketing Company), at market-based rates. For 2002, we again, through
a competitive bidding process, entered into a one-year contract 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 pleading with the Securities and Exchange
Commission (SEC) relating to our agreement to purchase 450 megawatts of capacity
and energy from Marketing Company during 2001 (the 2001 Marketing Company -
AmerenUE agreement). The pleading requested an investigation into the
contractual relationship between us, Marketing Company and our affiliate,
AmerenEnergy Generating Company (Generating Company), in the context of the 2001
Marketing Company - AmerenUE agreement and requested that the SEC find that such
relationship violates a provision of PUHCA which requires state utility
commission approval of power sales contracts between an electric utility company
and an affiliated electric wholesale generator, like Generating Company. We
believe that the MoPSC's approval of the power sales agreement under PUHCA is
not required because Generating Company is not a party to the agreement. As a
remedy, the MoPSC proposes that the SEC require us to
7
contract directly with Generating Company and submit such contract to the MoPSC
for review. The SEC has not responded to this matter to date. On May 9, 2002,
the MoPSC filed a similar pleading with the SEC relating to AmerenUE's agreement
to purchase 200 megawatts of capacity and energy from Marketing Company during
2002. At this time, management is unable to predict the outcome of these
pleadings or the ultimate impact on our future financial position, results of
operations or liquidity.
Illinois
In December 1997, the Governor of Illinois signed the Electric Service
Customer Choice and Rate Relief Law of 1997 (the Illinois Law) providing for
electric utility restructuring in Illinois. This legislation introduced
competition into the retail supply of electric energy in Illinois. Illinois
residential customers were offered choice in suppliers on May 1, 2002.
Industrial and commercial customers were already offered this choice. 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 to have a material adverse effect on our
business either.
In addition, the Illinois Law contains a provision freezing residential
electric rates through January 1, 2005. Legislation has been introduced in the
Illinois House of Representatives and Senate that would extend the rate freeze
to December 31, 2006. At this time, we cannot predict whether that legislation
will ultimately be passed.
Federal - Midwest ISO and Alliance RTO
In December 1999, the Federal Energy Regulatory Commission (FERC) issued
Order 2000, requiring all utilities, subject to FERC jurisdiction, to state
their intentions for joining a regional transmission organization (RTO). RTOs
are independent organizations that will functionally control the transmission
assets of utilities in order to improve the wholesale power market. Since
January 2001, we along with several other utilities have been seeking approval
from the FERC to participate in an RTO known as the Alliance RTO. We had
previously been a member of the Midwest Independent System Operator (MISO) and
recorded a pretax charge to earnings in 2000 of $17 million ($10 million after
taxes) for an exit fee and other costs when we left that organization. We felt
the for-profit Alliance RTO business model was superior to the not-for-profit
MISO business model and provided us with a more equitable return on our
transmission assets.
In late 2001, the FERC issued an order that rejected the formation of the
Alliance RTO and ordered the Alliance RTO companies and the MISO to discuss how
the Alliance RTO business model could be accommodated within the MISO. On April
25, 2002, after the Alliance RTO and MISO failed to reach an agreement, and
after a series of filings by the two parties with the FERC, the FERC issued a
declaratory order setting forth the division of responsibilities between the
MISO and National Grid (the managing member of the transmission company formed
by the Alliance companies) and approved the rate design and the revenue
distribution methodology proposed by the Alliance companies. However, the FERC
denied a request by the Alliance companies and the National Grid to purchase
certain services from the MISO at incremental cost rather than MISO's full
tariff rates. The FERC also ordered the MISO to return the exit fee paid by
AmerenUE to leave the MISO, provided AmerenUE returns to the MISO and agrees to
pay its proportional share of the startup and ongoing operational expenses of
the MISO. Moreover, the FERC required the Alliance companies to select the RTO
in which they will participate within thirty days of the order. At this time, we
continue to evaluate our alternatives and are in the process of determining the
impact that the FERC's April 2002 ruling will have on our future financial
condition, results of operations or liquidity.
NOTE 3 - Related Party Transactions
AmerenUE has transactions in the normal course of business with Ameren
Corporation, our parent company, and its subsidiaries. These transactions are
primarily comprised of power purchases and sales and services received or
rendered. Intercompany power purchases from joint dispatch and other agreements
were approximately $27 million for the three months ended March 31, 2002,
compared to $23 million for the three months ended March 31, 2001. Intercompany
power sales totaled $20 million for the three months ended March 31, 2002,
compared to $28 million for the three months ended March 31, 2001. Intercompany
receivables included in Other Accounts and Notes Receivable were approximately
$14 million as of March 31, 2002 (December 31, 2001 - $38 million). Intercompany
payables included in Accounts and Wages Payable totaled approximately $47
million as of March 31, 2002 (December 31, 2001 - $70 million).
8
Support services provided by our affiliates, Ameren Services and
AmerenEnergy, including wages, employee benefits, professional services and
other expenses are based on actual costs incurred. For the three months ended
March 31, 2002, Other Operating Expenses provided by Ameren Services and
AmerenEnergy totaled $48 million, compared to $47 million for the same period in
2001.
We have the ability to borrow up to approximately $425 million from Ameren
or our affiliate, AmerenCIPS, through a regulated money pool agreement. The
total amount available to us at any given time from the regulated money pool is
reduced by the amount of borrowings by AmerenCIPS or Ameren Services, but
increased to the extent Ameren, AmerenCIPS or Ameren Services have surplus funds
or the availability of other external borrowing sources. AmerenUE, AmerenCIPS
and Ameren Services rely on the regulated money pool to coordinate and provide
for certain short-term cash and working capital requirements. Ameren Services
administers the regulated money pool. 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 March 31, 2002, the average
interest rate for the regulated money pool was 1.79% (2001 - 5.50%). As of March
31, 2002, we had outstanding intercompany payables of $192 million through the
regulated money pool. At December 31, 2001, we had outstanding intercompany
receivables of $84 million through the regulated money pool. At March 31, 2002,
at least $357 million was available through the regulated money pool.
NOTE 4 - Derivative Financial Instruments
We utilize derivatives principally to manage the risk of changes in market
prices for natural gas, fuel, electricity and emission credits. Price
fluctuations in natural gas, fuel and electricity cause:
o an unrealized appreciation or depreciation of our firm commitments to
purchase or sell when purchase or sales prices under the firm commitment
are compared with current commodity prices;
o market values of fuel and natural gas inventories or purchased power to
differ from the cost of those commodities in inventory or under the firm
commitment; and
o actual cash outlays for the purchase of these commodities in certain
circumstances to differ from anticipated cash outlays.
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 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 price risk for AmerenUE.
As of March 31, 2002, we recorded the fair value of derivative financial
instrument assets of $20 million in Other Assets and the fair value of
derivative financial instrument liabilities of $24 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.
For the three months ended March 31, 2002, the pretax net gain, which
represented the impact of discontinued cash flow hedges, the ineffective portion
of cash flow hedges, as well as the reversal of amounts previously recorded in
OCI due to transactions going to delivery or settlement, was approximately $1
million.
As of March 31, 2002, the entire net loss on power forward derivative
instruments of approximately $6 million, or approximately $4 million after tax,
accumulated in OCI is expected to be recognized in earnings during the next
twelve months upon delivery of the commodity being hedged.
9
We also hold a call option for coal with a supplier. This option to
purchase coal expires October 15, 2003. The entire gain of approximately $5
million, or approximately $3 million after tax, accumulated in OCI is expected
to be recognized in earnings prior to that date.
Other Derivatives
We enter into option transactions to manage our positions in sulfur dioxide
(SO2) allowances, coal, and electricity. Most of these transactions are treated
as non-hedge transactions under SFAS 133. Therefore, the net change in the
market value of these options is recorded as Miscellaneous, net in the statement
of income and was immaterial at March 31, 2002.
NOTE 5 - Subsequent Event
On April 28, 2002, Ameren entered into an agreement with The AES
Corporation to purchase all or the outstanding stock of CILCORP Inc. CILCORP is
the parent company of Peoria-based Central Illinois Light Company, which
operates as CILCO. Ameren also agreed to acquire AES Medina Valley (No. 4),
L.L.C. which indirectly owns a 40 megawatt, gas-fired electric generation plant.
The total purchase price is approximately $1.4 billion, subject to adjustment
for changes in CILCORP's working capital, and includes the assumption of CILCORP
and AES Medina Valley debt at closing, estimated at approximately $900 million,
with the balance of the purchase price in cash. Ameren currently expects to
finance a significant portion of the cash component of the purchase price
through the issuance of new common equity.
The purchase will include CILCORP's regulated natural gas and electric
businesses in Illinois serving approximately 200,000 and 205,000 customers,
respectively, of which approximately 150,000 are combination electric and gas
customers. In addition, the purchase includes approximately 1,200 megawatts of
largely coal-fired generating capacity most of which is expected to be
nonregulated by closing.
Upon completion of the acquisition, expected within 12 months, CILCO will
become an Ameren subsidiary, but will remain a separate utility company,
operating as AmerenCILCO. The transaction is subject to the approval of the
Illinois Commerce Commission, the SEC, the FERC, the expiration of the waiting
period under the Hart-Scott-Rodino Act and other customary closing conditions.
For the period ended December 31, 2001, CILCORP had revenues of $815
million, operating income of $126 million, and net income from continuing
operations of $28 million, and as of December 31, 2001 had total assets of $1.8
billion.
10
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
operating 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 operating 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
nonregulated operations. Subsidiaries include AmerenEnergy Generating
Company (Generating Company) that operates nonregulated electric
generation in Missouri and Illinois, AmerenEnergy Marketing Company
(Marketing Company), which markets power for periods over one year, and
AmerenEnergy Fuels and Services Company, which procures fuel and
manages the related risks for Ameren affiliated companies.
o AmerenEnergy, Inc. which serves as a power marketing and risk
management agent for Ameren affiliated companies for transactions of
primarily less than one year.
o Electric Energy, Inc. (EEI), which owns and/or operates electric
generation and transmission facilities in Illinois. We have a 40%
ownership interest in EEI and have accounted for it under the equity
method of accounting.
o Ameren Services Company, which provides shared support services to
Ameren and its subsidiaries, including AmerenUE. 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 Management's Discussion and Analysis of Financial Condition and Results
of Operations that appears in our Annual Report on Form 10-K for the
period ended December 31, 2001.
o The audited financial statements and related notes that appear in our
Annual Report on Form 10-K for the period ended December 31, 2001.
When we refer to AmerenUE, our, we or us, we are referring to Union
Electric Company. All dollar amounts are in millions, unless otherwise
indicated.
Our results of operations and financial position are impacted by many
factors, including both controllable and uncontrollable factors. Weather,
economic conditions, and the actions of key customers or competitors can
significantly impact the demand for our services. Our results are also impacted
by seasonal fluctuations caused by winter heating and summer cooling demand.
With nearly all of our revenues subject to regulation by various state and
federal agencies, decisions by regulators can have a material impact on the
price we charge for our services. We principally utilize coal, natural gas and
nuclear fuel in our operations. The prices for these commodities can fluctuate
significantly due to the world economic and political environment, weather,
production levels and many other factors. We do not have fuel recovery
mechanisms in Missouri and Illinois, but do have gas cost recovery mechanisms in
each state. We employ various risk management strategies in order to try to
reduce our exposure to commodity risks and other risks inherent in our business.
The reliability of our power plant, and transmission and distribution systems,
and the level of operating and administrative costs and capital investment are
key factors that we seek to control in order to optimize our results of
operations, cash flows and financial position.
RESULTS OF OPERATIONS
Our net income increased by 34% to $51 million in the first quarter of 2002
from $38 million in the first quarter of 2001. In the first quarter of 2001, we
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." See Accounting Matters. As a result, income before
cumulative effect of change in
11
accounting principle in the first quarter of 2002 was $51 million compared to
$43 million in the first quarter of 2001. Income before cumulative effect of
change in accounting principle increased in the first quarter of 2002 versus the
prior year primarily due to internal weather-normalized growth and the $9
million after-tax benefit of the lack of estimated credits to Missouri electric
customers due to the expiration of our incentive rate plan on June 30, 2001.
Partially offsetting these benefits was the effect of the extremely mild winter
weather in our service territory. According to National Weather Service data,
there were approximately 15% fewer heating degree days in our service territory
in the first quarter of 2002 as compared to 2001 and normal weather conditions.
As a result, weather-sensitive residential electric kilowatt-hour sales
decreased by 5%, commercial electric kilowatt-hour sales decreased by 3% and gas
sales decreased by 9% in the first quarter of 2002 compared to 2001. In
addition, industrial electric kilowatt-hour sales decreased 7% due to the
continued soft economy.
Despite the warmer winter weather, total electric revenues increased 15%
for the first quarter of 2002, compared to the year-ago period, primarily due to
higher interchange sales. However, we realized lower margins on these sales
compared to the prior year, due to lower wholesale electricity prices.
Recent Developments
On April 28, 2002, Ameren entered into an agreement with The AES
Corporation to purchase all of the outstanding stock of CILCORP Inc. CILCORP is
the parent company of Peoria-based Central Illinois Light Company, which
operates as CILCO. Ameren also agreed to acquire AES Medina Valley (No. 4),
L.L.C. which indirectly owns a 40 megawatt, gas-fired electric generation plant.
The total purchase price is approximately $1.4 billion, subject to adjustment
for changes in CILCORP's working capital, and includes the assumption of CILCORP
and AES Medina Valley debt at closing, estimated at approximately $900 million,
with the balance of the purchase price in cash. Ameren currently expects to
finance a significant portion of the cash component of the purchase price
through the issuance of new common equity.
The purchase will include CILCORP's regulated natural gas and electric
businesses in Illinois serving approximately 200,000 and 205,000 customers,
respectively, of which approximately 150,000 are combination electric and gas
customers. In addition, the purchase includes approximately 1,200 megawatts of
largely coal-fired generating capacity most of which is expected to be
nonregulated by closing.
Upon completion of the acquisition, expected within 12 months, CILCO will
become an Ameren subsidiary, but will remain a separate utility company,
operating as AmerenCILCO. The transaction is subject to the approval of the
Illinois Commerce Commission, the Securities and Exchange Commission (SEC), the
Federal Energy Regulatory Commission (FERC), the expiration of the waiting
period under the Hart-Scott-Rodino Act and other customary closing conditions.
For the period ended December 31, 2001, CILCORP had revenues of $815
million, operating income of $126 million, and net income from continuing
operations of $28 million, and as of December 31, 2001 had total assets of $1.8
billion.
As a result of the continuing uncertainty associated with our pending
Missouri electric rate 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 our debt and AmerenCIPS debt on negative credit watch and placed the
ratings of Generating Company's debt on positive credit watch. However, Standard
& Poor's stated they expect the corporate credit ratings of Ameren and its
subsidiaries to be in the "A" rating category following completion of the
acquisition. Moody's Investor Service stated they envisioned a one notch
downgrade of Ameren's issuer, senior unsecured debt and commercial paper
ratings. Currently, Ameren's corporate credit rating is A+ at Standard and
Poor's and A2 at Moody's. If the ratings of our first mortgage bonds fall below
investment grade, lenders under our $300 million revolving credit facility may
elect not to make advances and/or declare outstanding borrowings due and
payable. In addition, a decrease in Ameren's ratings may indirectly reduce our
access to capital and/or increase the costs of borrowings resulting in a
negative impact on earnings.
12
Electric Operations
The following table represents the favorable (unfavorable) variation for
the three months ended March 31, 2002 from the comparable period in 2001:
- --------------------------------------------------------------------------------
Three Months
- --------------------------------------------------------------------------------
Operating Revenues:
Credit to customers......................................... $ 15
Effect of abnormal weather (estimate)....................... (12)
Growth and other (estimate)................................. 18
Interchange sales........................................... 66
- --------------------------------------------------------------------------------
87
Fuel and Purchased Power:
Fuel:
Generation................................................ $ 8
Price..................................................... 6
Purchased power ............................................ (89)
- --------------------------------------------------------------------------------
(75)
- --------------------------------------------------------------------------------
Change in electric margin $ 12
- --------------------------------------------------------------------------------
Electric margins increased $12 million in the first three months of 2002
compared to the year-ago quarter. Revenues were favorably impacted in 2002 by
the lack of estimated credits to Missouri electric customers (see Note 2 -
"Regulatory Matters" to the financial statements). We also experienced growth in
electric revenues due to the expansion of our weather-normalized native load,
sales of SO2 allowances and an 80% increase in interchange sales. However, these
increased interchange revenues were more than offset by the related increase in
purchased power, resulting in lower margins than 2001. The increases in revenues
were also partially offset by decreases in weather-sensitive residential and
commercial sales caused by the milder winter weather referenced above, and lower
industrial sales resulting from the continued soft economy in our service
territory.
Interchange revenues for the first quarter of 2002 included sales to
related parties of $20 million, compared to $28 million in the first quarter of
2001. Fuel and purchased power costs for the first quarter of 2002 included
purchases of $27 million from related parties under joint dispatch and other
agreements, compared to $23 million for the first quarter of 2001. See Note 3 -
"Related Party Transactions" to the financial statements.
Gas Operations
Our gas revenues decreased $19 million, and our gas costs decreased $14
million, in first quarter of 2002 as compared to the year-ago quarter primarily
due to reduced sales of 9% caused by the milder winter weather and lower natural
gas prices. As a result, our gas margins decreased by $5 million in the first
quarter of 2002 as compared to the same period a year ago.
Other Operating Expenses
Other operating expenses in the first quarter of 2002 were comparable to
the year-ago period. Ameren Services and AmerenEnergy provided services to us
for the three months ended March 31, 2002 of approximately $48 million (2001 -
$47 million) that were included in Other Operating Expenses. See Note 3 -
"Related Party Transactions" to the financial statements.
Maintenance expenses decreased $3 million in the first quarter of 2002
compared to the year-ago period, primarily due to decreased coal power plant
maintenance, partially offset by higher tree-trimming expenses, which were
accelerated, in part, to take advantage of mild weather.
Depreciation and amortization expenses increased $3 million in the first
quarter of 2002 compared to the year-ago period, primarily due to an increase in
depreciable property related to the investment in our coal electric generating
plants.
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Taxes
Income tax expense decreased $3 million in the first quarter of 2002,
compared to the year-ago period, primarily due to a lower effective tax rate.
Other tax expense increased $2 million in the first quarter of 2002,
compared to the year-ago period, primarily due to higher Missouri property tax
assessments and higher gross receipts taxes resulting from increased electric
sales.
Other Income and Deductions
Other income and deductions decreased $4 million in the first quarter of
2002, compared to the year-ago period primarily due to lower intercompany
interest earned on funds loaned to the regulated money pool resulting from lower
average intercompany notes receivable balances. See Note 3 - "Related Party
Transactions" to financial statements.
Interest
Interest expense decreased $3 million in the first quarter of 2002 compared
to the year-ago period primarily due to lower interest rates on our variable
rate environmental bonds ($2 million), as well as lower interest expense
associated with a decreased balance under our nuclear fuel lease ($1 million).
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. At March 31, 2002, we had an accrual representing the
estimated credit that we expect to pay our Missouri electric customers of $40
million for the plan year ended June 30, 2001. In 2002, the Missouri Public
Service Commission (MoPSC) Staff and the Missouri Office of Public Counsel (OPC)
Staff filed testimony with the MoPSC on this matter. Combined, the MoPSC Staff
and OPC Staff recommend that the credit to customers for the plan year ended
June 30, 2001, should approximate $80 million. The MoPSC is not bound by their
recommendations. To date, a procedural schedule and hearing dates on this matter
have not been established by the MoPSC. At this time, we continue to believe
that our accrual is adequate in all material respects.
Following expiration of the experimental alternative regulation plan on
June 30, 2001, the MoPSC Staff filed an excess earnings complaint against us.
Based upon a January 2002 MoPSC order, on March 1, 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 is based on a return
to traditional cost of service ratemaking, a return on equity ranging from 8.91%
to 9.91%, a reduction in our depreciation rates, and other cost of service
adjustments. The MoPSC is not bound by the Staff's recommendation.
On May 10, 2002, we filed rebuttal testimony in response to the MoPSC
Staff's recommendation. In our testimony, we stated that a return to traditional
cost of service ratemaking would result in an increase in our annual Missouri
electric revenues by approximately $150 million. Our position is based on a
12.5% return on equity, higher depreciation rates and other adjustments.
However, a key component of our testimony is our recommendation that a new
alternative rate regulation plan (Alt Reg Plan) be adopted by the MoPSC. In our
filing, we included a new Alt Reg Plan proposal. Key provisions of the Alt Reg
Plan include the following:
o A three-year plan from July 1, 2002 through June 30, 2005 which would
require us to share earnings over certain regulatory return on equity
(ROE) thresholds for the 12 months ending July 1 through June 30;
o The proposed earnings sharing grid would require us to provide sharing
credits of $17 million if our regulatory ROE is between 10.5% and
12.5%. Additional credits of 55% of our earnings between a regulatory
ROE of 12.5% and 15% would be provided, 90% of earnings between a
regulatory ROE of 15% and 16%, and 100% of any earnings above 16%.
o An immediate one-time credit to customers bills of $15 million;
o An annualized $15 million permanent rate reduction, retroactive to
April 1, 2002;
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o An immediate funding of $5 million to a low-income customer assistance
program and $5 million to an economic development program;
o A commitment of $1.5 billion to $1.75 billion in energy infrastructure
investment from January 1, 2002 through June 30, 2005.
Hearings for this case are scheduled to commence in mid-July 2002 and be
completed in early August 2002. A final decision on this matter may not occur
until the fourth quarter of 2002. In the interim, we plan to continue
negotiations with all pertinent parties with the intent to continue with an
incentive regulation plan. We cannot predict the outcome of the MoPSC's decision
in this matter or its impact on our financial statements, results of operations
or liquidity. However, the impact could be material.
LIQUIDITY AND CAPITAL RESOURCES
Operating
Our cash flows provided by operating activities decreased $44 million to
$85 million in the first quarter of 2002 compared to the year-ago period,
primarily due to changes in working capital requirements resulting from a
decrease in accounts and wages payable utilizing cash received from the decrease
in receivables. These decreases were partially offset by increased earnings.
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 (maturities
generally within 1 to 45 days).
We have several bank credit agreements expiring in 2002 that support our
commercial paper program totaling $430 million. At March 31, 2002, all of these
bank credit agreements were unused and available. Ameren expects to replace
these bank credit agreements prior to their maturity.
We also have the ability to borrow up to approximately $425 million from
Ameren or from AmerenCIPS, through a regulated money pool agreement. The total
amount available to us at any given time from the regulated money pool is
reduced by the amount of borrowings by AmerenCIPS or Ameren Services, but
increased to the extent Ameren, AmerenCIPS or Ameren Services have surplus funds
or the availability of other external borrowing sources. AmerenUE, AmerenCIPS
and Ameren Services rely on the regulated money pool to coordinate and provide
for certain short-term cash and working capital requirements. Ameren Services
administers the regulated money pool. 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 March 31, 2002, the average
interest rate for the regulated money pool was 1.79% (2001 - 5.50%). As of March
31, 2002, we had outstanding intercompany payables of $192 million and at least
$357 million available through the regulated money pool. At December 31, 2001,
we had outstanding intercompany receivables of $84 million through the regulated
money pool.
We also have a lease agreement that provides for the financing of nuclear
fuel. At March 31, 2002, the maximum amount that could be financed under the
agreement was $120 million, of which $67 million was utilized.
Our short-term 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 March 31, 2002, we were in compliance
with these provisions.
Investing
Our net cash used in investing activities was $19 million in the first
quarter of 2002 compared to $76 million in the first quarter of 2001. In the
first quarter of 2002, construction expenditures were $101 million (2001 - $89
million), primarily related to various upgrades at our coal power plants and
further construction of combustion turbine generating units. Our capital
expenditures are expected to approximate
15
$500 million in 2002. Also, during the first quarter of 2002, AmerenUE was
repaid $84 million (2001 - $18 million) from the regulated money pool.
Financing
Our cash flows used in financing activities were $69 million in the first
quarter of 2002 compared to $48 million in the year-ago period. Our principal
financing activities for the period included the redemption of short-term debt
and the payment of dividends, partially offset by the issuance of intercompany
notes payable.
In May 2002, we filed a shelf registration statement with the SEC on Form
S-3 that upon its effectiveness will allow 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 for general corporate purposes,
including the repayment of short-term debt incurred to finance construction
expenditures and other working capital needs. This registration has not yet been
declared effective by the SEC.
In the ordinary course of business, we evaluate several strategies to
enhance our financial position, earnings, and liquidity. These strategies may
include potential acquisitions, divestitures, opportunities to reduce costs or
increase revenues, and other strategic initiatives in order to increase
shareholder value. We are unable to predict which, if any, of these initiatives
will be executed, as well as the impact these initiatives may have on our future
financial position, results of operations or liquidity.
Electric Industry Restructuring
Illinois
See Note 2 - "Rate and Regulatory Matters" to the financial statements.
Federal - Midwest ISO and Alliance RTO
See Note 2 - "Rate and Regulatory Matters" to the financial statements.
ACCOUNTING MATTERS
Critical Accounting Policies
Preparation of the financial statements and related disclosures in
compliance with generally accepted accounting principles requires the
application of appropriate technical accounting rules and guidance, as well as
the use of estimates. Our application of these policies involves judgments
regarding many factors, which, in and of themselves, could materially impact the
financial statements and disclosures. A future change in the assumptions or
judgments applied in determining the following matters, among others, could have
a material impact on future financial results. In the table below, we have
outlined those accounting policies that we believe are most difficult,
subjective or complex:
Accounting Policy Judgments/Uncertainties Affecting Application
- ----------------- ---------------------------------------------
Regulatory Mechanisms & Cost Recovery
We defer costs as regulatory o Regulatory environment, external
assets in accordance with SFAS 71 regulatory decisions and requirements
and make investments that we o Anticipated future regulatory
assume we will be able to decisions and their impact
collect in future rates. o Impact of deregulation and
competition on ratemaking process
and ability to recover costs
Nuclear Plant Decommissioning Costs
In our rates and earnings we assume o Estimates of future decommissioning
the Department of Energy will o Availability of facilities for waste disposal
develop a permanent storage site o Approved methods for waste disposal
for spent nuclear fuel, the and decommissioning
Callaway plant will have a useful o Useful lives of nuclear power plants
life of 40 years and estimated costs
to dismantle the plant are accurate.
See Note 12 to our financial
statements for the year ended
December 31, 2001.
16
Environmental Costs
We accrue for all known environmental o Extent of contamination
contamination where remediation can o Responsible party determination
be reasonably estimated, but some of o Approved methods of cleanup
our operations have existed for over o Present and future legislation
100 years and previous contamination governmental regulations and
may be unknown to us. standards
o Results of ongoing research and
development regarding environmental
impacts
Unbilled Revenue
At the end of each period, we o Projecting customer energy usage
estimate, based on expected usage, o Estimating impacts of weather and
the amount of revenue to record for other usage-affecting factors
services that have been provided to for the unbilled period
customers, but not billed. This
period can be up to one month.
Benefit Plan Accounting
Based on actuarial calculations, we o Future rate of return on pension
accrue costs of providing future and other plan assets
employee benefits in accordance with o Interest rates used in valuing
SFAS 87, 106 and 112. See Note 10 benefit obligation
106 and 112. See Note 10 to our o Healthcare cost trend rates
financial statements for the year
ended December 31, 2001.
Derivative Financial Instruments
We record all derivatives at their o Market conditions in the energy
fair market value in accordance industry, especially the effects of
with SFAS 133. The identification price volatility on contractual
and classification of a derivative commodity commitments
and the fair value of such derivative o Regulatory and political
must be determined. See Note 4 to our environments and requirements
financial statements for the year o Fair value estimations on longer
ended December 31, 2001. term contracts
Impact of Future Accounting Pronouncements
See Note 1 - "Summary of Significant Accounting Policies" to the financial
statements.
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk.
Market risk represents the risk of changes in value of a physical asset or
financial instrument, derivative or non-derivative, caused by fluctuations in
market variables (e.g. interest rates, etc.). The following discussion of
Ameren's, including AmerenUE's, risk management activities includes
"forward-looking" statements that involve risks and uncertainties. Actual
results could differ materially from those projected in the "forward-looking"
statements. Ameren manages market risks in accordance with established policies,
which may include entering into various derivative transactions. In the normal
course of business, Ameren and our Company also face risks that are either
non-financial or non-quantifiable. Such risks principally include business,
legal, and operational risk and are not represented in the following analysis.
Ameren's risk management objective is to optimize its physical generating
assets within prudent risk parameters. Risk management policies are set by a
Risk Management Steering Committee, which is comprised of senior-level Ameren
officers.
17
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 March 31, 2002, if interest rates
increased by 1%, our annual interest expense would increase by approximately $5
million and net income would decrease by approximately $3 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
Over 95% of the required 2002 supply of coal for our coal plants has been
acquired at fixed prices. As such, we have minimal coal price risk for 2002. In
addition, approximately 70% of our coal requirements through 2006 are covered by
contracts.
Fair Value of Contracts
We utilize derivatives principally to manage the risk of changes in market
prices for natural gas, fuel, electricity and emission credits. Price
fluctuations in natural gas, fuel and electricity cause:
o an unrealized appreciation or depreciation of our firm commitments to
purchase or sell when purchase or sales prices under the firm commitment
are compared with current commodity prices;
o market values of fuel and natural gas inventories or purchased power to
differ from the cost of those commodities in inventory and under firm
commitment; and
o actual cash outlays for the purchase of these commodities to differ from
anticipated cash outlays.
The derivatives that we use to hedge these risks are dictated by risk
management policies and include forward contracts, futures contracts, options
and swaps. We continually assess our supply and delivery commitment positions
against forward market prices and internally forecast forward prices and modify
our exposure to market, credit and operational risk by entering into various
offsetting transactions. In general, these transactions serve to reduce our
price risk.
The following summarizes changes in the fair value of all contracts marked
to market during the first quarter of 2002:
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Fair value of contracts at January 1, 2002 $ (2)
Contracts at January 1, 2002 which were realized or otherwise
settled during first quarter of 2002 --
Changes in fair values attributable to changes in valuation
techniques and assumptions --
Fair value of new contracts entered into during first quarter 2002 --
Other changes in fair value (2)
- --------------------------------------------------------------------------------
Fair value of contracts outstanding at March 31, 2002 $ (4)
- --------------------------------------------------------------------------------
18
Fair value of contracts as of March 31, 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) (2) -- -- -- (2)
Prices based on models and other
valuation methods (c) (3) 2 (1) -- (2)
- -----------------------------------------------------------------------------------------------------------
Total $ (5) $ 2 $ (1) $ -- $ (4)
- -----------------------------------------------------------------------------------------------------------
(a) Nearly 100% of contracts were with investment-grade rated counterparties.
(b) Principally power forward hedges valued based on NYMEX prices for over-the-counter contracts.
(c) Principally coal and SO2 options valued based on a Black-Scholes model that includes information
from external sources and our estimates.
SAFE HARBOR STATEMENT
Statements made in this report which are not based on historical facts, are
"forward-looking" and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
"forward-looking" statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans, strategies, objectives, events, conditions and
financial performance. In connection with the "Safe Harbor" provisions of the
Private Securities Litigation Reform Act of 1995, we are providing this
cautionary statement to identify important factors that could cause actual
results to differ materially from those anticipated. The following factors, in
addition to those discussed elsewhere in this report and in the Annual Report on
Form 10-K for 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 our pending 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 and the Alliance RTO;
o availability and future market prices for fuel and purchased power,
electricity, and natural gas, including the use of financial and derivative
instruments and volatility of changes in market prices;
o average rates for electricity in the Midwest;
o business and economic conditions;
o the impact of the adoption of new accounting standards;
o interest rates and the availability of capital;
o actions of rating agencies and the effects of such actions;
o weather conditions;
o generation plant construction, installation and performance;
o the effects of strategic initiatives, including acquisitions and
divestitures;
o operation of nuclear power facilities and decommissioning costs;
o the impact of current environmental regulations on utilities and generating
companies and the expectation that more stringent requirements will be
introduced over time, which could potentially have a negative financial
effect;
o future wages and employee benefits costs;
o competition from other generating facilities including new facilities that
may be developed in the future;
o delays in receipt of regulatory approvals for the acquisition of CILCORP or
unexpected adverse conditions or terms of those approvals;
o difficulties in integrating CILCO with Ameren's other businesses;
o changes in the coal markets, environmental laws or regulations or other
factors adversely impacting synergy assumptions in connection with the
CILCORP acquisition;
19
o disruptions of the capital markets or other events making AmerenUE's access
to necessary capital more difficult or costly;
o cost and availability of transmission capacity for the energy generated by
our generating facilities or required to satisfy energy sales made by
AmerenUE; and
o legal and administrative proceedings.
20
PART II - OTHER INFORMATION
ITEM 1. Legal Proceedings.
Reference is made to Item 3. Legal Proceedings in Part I of our Annual
Report on Form 10-K for the year ended December 31, 2001 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. With respect to nine of those lawsuits, the Ameren
companies have reached settlements with the plaintiffs for monetary amounts not
material to the Ameren companies and in three cases, the Ameren companies have
been voluntarily dismissed.
Twenty-two additional lawsuits claiming injury from asbestos exposure have
been filed against the Ameren companies since year-end 2001. These lawsuits,
like the previous cases, were mostly filed in the Circuit Court of Madison
County, Illinois, involve a large number of total defendants (over one hundred
in many cases) and seek unspecified damages in excess of $50,000, which, if
proved, typically would be shared among the named defendants. Currently, thirty
asbestos-related lawsuits are pending against the Ameren companies. 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 6. Exhibits and Reports on Form 8-K.
(a) Exhibits Incorporated by Reference.
10.1 - Power Sales Agreement between AmerenEnergy Marketing
Company and AmerenUE dated March 20, 2002 (March 31,
2002 AmerenEnergy Generating Company Form 10-Q,
Exhibit 10.1).
(b) Reports on Form 8-K. AmerenUE filed a report on Form 8-K
dated January 7, 2002 incorporating a press release issued by
Ameren Corporation relating to the earnings complaint case
filed by the Missouri Public Service Commission staff against
AmerenUE and announcing a revision to Ameren Corporation's
2001 earnings estimate.
Note: Reports of Ameren Corporation on Forms 8-K, 10-Q and 10-K are
on file with the SEC under File Number 1-14756.
Reports of Central Illinois Public Service Company on Forms
8-K, 10-Q and 10-K are on file with the SEC under File Number
1-3672.
Reports of AmerenEnergy Generating Company on Forms 8-K, 10-Q
and 10-K are on file with the SEC under File Number 333-56594.
21
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
UNION ELECTRIC COMPANY
(Registrant)
By /s/ Martin J. Lyons
-----------------------
Martin J. Lyons
Controller
(Principal Accounting Officer)
Date: May 15, 2002
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