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 1-14756
AMEREN CORPORATION
(Exact name of registrant as specified in its charter)
Missouri 43-1723446
(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 Ameren Corporation's common stock as of November 12,
2002: Common Stock, $.01 par value - 153,613,096
AMEREN CORPORATION
INDEX
Page
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PART I. Financial Information
ITEM 1. Financial Statements (Unaudited)
Consolidated Balance Sheet at September 30, 2002 and
December 31, 2001 . . . . . . . . . . . . . . . . . . . . . . 2
Consolidated Statement of Income for the three and nine
months ended September 30, 2002 and 2001 . . . . . . . . . . 3
Consolidated Statement of Cash Flows for the nine months
ended September 30, 2002 and 2001 . . . . . . . . . . . . . . 4
Consolidated Statement of Common Stockholders' Equity for
the three and nine months ended September 30, 2002 and 2001 . 5
Notes to Consolidated Financial Statements . . . . . . . . . 6
ITEM 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . . . . 17
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk . 29
ITEM 4. Controls and Procedures . . . . . . . . . . . . . . . . . . . 31
PART II. Other Information
ITEM 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . 33
ITEM 5. Other Information . . . . . . . . . . . . . . . . . . . . . . 33
ITEM 6. Exhibits and Reports on Form 8-K . . . . . . . . . . . . . . 34
SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
CERTIFICATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
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.
PART I FINANCIAL INFORMATION
ITEM 1. Financial Statements
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(Unaudited, in millions, except per share amounts)
September 30, December 31,
2002 2001
----------- ------------
ASSETS:
Property and plant, at original cost:
Electric $ 14,245 $ 13,664
Gas 551 532
Other 144 105
-------- --------
14,940 14,301
Less accumulated depreciation and amortization 6,808 6,535
-------- --------
8,132 7,766
Construction work in progress:
Nuclear fuel in process 124 97
Other 433 564
-------- --------
Total property and plant, net 8,689 8,427
-------- --------
Investments and other assets:
Investments 38 39
Nuclear decommissioning trust fund 162 187
Other 153 114
-------- --------
Total investments and other assets 353 340
-------- --------
Current assets:
Cash and cash equivalents 629 67
Accounts receivable - trade (less allowance
for doubtful accounts of $8 and $9, respectively) 323 218
Unbilled revenue 159 171
Other accounts and notes receivable 27 71
Materials and supplies, at average cost -
Fossil fuel 148 159
Other 132 136
Other 42 41
-------- --------
Total current assets 1,460 863
-------- --------
Regulatory assets:
Deferred income taxes 552 604
Other 160 167
-------- --------
Total regulatory assets 712 771
-------- --------
Total Assets $ 11,214 $ 10,401
======== ========
CAPITAL AND LIABILITIES:
Capitalization:
Common stock, $.01 par value, 400.0 shares
authorized - shares outstanding of 153.5
and 138.0, respectively $ 2 $ 1
Other paid-in capital, principally premium on
common stock 2,180 1,614
Retained earnings 1,868 1,733
Accumulated other comprehensive income 7 5
Other (10) (4)
-------- --------
Total common stockholders' equity 4,047 3,349
-------- --------
Preferred stock not subject to mandatory redemption 194 235
Long-term debt 3,484 2,835
-------- --------
Total capitalization 7,725 6,419
-------- --------
Minority interest in consolidated subsidiaries 14 4
Current liabilities:
Current maturities of long-term debt 255 139
Short-term debt 6 641
Accounts and wages payable 175 392
Accumulated deferred income taxes 5 58
Taxes accrued 346 132
Other 243 219
-------- --------
Total current liabilities 1,030 1,581
-------- --------
Accumulated deferred income taxes 1,602 1,563
Accumulated deferred investment tax credits 152 158
Regulatory liabilities 153 172
Other deferred credits and liabilities 538 504
-------- --------
Total Capital and Liabilities $ 11,214 $ 10,401
======== ========
See Notes to Consolidated Financial Statements.
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Unaudited, in millions, except per share amounts)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -------------------
2002 2001 2002 2001
OPERATING REVENUES: ------- ------- ------- -------
Electric $ 1,201 $ 1,380 $ 3,132 $ 3,241
Gas 30 40 202 255
Other 1 2 4 7
------- ------- ------- -------
Total operating revenues 1,232 1,422 3,338 3,503
------- ------- ------- -------
OPERATING EXPENSES:
Operations
Fuel and purchased power 314 484 975 1,153
Gas 17 21 129 172
Other 197 173 567 518
------- ------- ------- -------
528 678 1,671 1,843
Maintenance 81 78 268 296
Depreciation and amortization 108 104 321 303
Income taxes 144 176 265 286
Other taxes 74 75 211 203
------- ------- ------- -------
Total operating expenses 935 1,111 2,736 2,931
------- ------- ------- -------
OPERATING INCOME 297 311 602 572
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction 1 4 3 8
Miscellaneous, net -
Miscellaneous income 5 10 13 14
Miscellaneous expense (3) (3) (46) (11)
Income taxes (1) (4) 9 (4)
------- ------- ------- -------
Total other income and (deductions) 2 7 (21) 7
------- ------- ------- -------
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest 57 51 162 149
Allowance for borrowed funds used during construction (1) (3) (4) (6)
Preferred dividends of subsidiaries 3 3 9 9
------- ------- ------- -------
Net interest charges and preferred dividends 59 51 167 152
------- ------- ------- -------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 240 267 414 427
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES - - - (7)
------- ------- ------- -------
NET INCOME $ 240 $ 267 $ 414 $ 420
======= ======= ======= =======
EARNINGS PER COMMON SHARE - BASIC:
Income before cumulative effect of change
in accounting principle $ 1.64 $ 1.94 $ 2.88 $ 3.11
Cumulative effect of change in accounting
principle, net of income taxes - - - (0.05)
------- ------- ------- -------
Net income $ 1.64 $ 1.94 $ 2.88 $ 3.06
======= ======= ======= =======
EARNINGS PER COMMON SHARE - ASSUMING DILUTION:
Income before cumulative effect of change
in accounting principle $ 1.63 $ 1.94 $ 2.87 $ 3.11
Cumulative effect of change in accounting
principle, net of income taxes - - - (0.05)
------- ------- ------- -------
Net income $ 1.63 $ 1.94 $ 2.87 $ 3.06
======= ======= ======= =======
AVERAGE COMMON SHARES OUTSTANDING 146.7 137.2 143.6 137.2
See Notes to Consolidated Financial Statements.
3
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited, in millions)
Nine Months Ended
September 30,
-----------------
2002 2001
----- -----
Cash Flows From Operating:
Net income $ 414 $ 420
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting principle - 7
Depreciation and amortization 321 303
Amortization of nuclear fuel 25 21
Amortization of debt issuance costs and premium/
discounts 6 4
Allowance for funds used during construction (7) (14)
Deferred income taxes, net 11 14
Deferred investment tax credits, net (6) (4)
Other 5 (11)
Changes in assets and liabilities:
Receivables, net (49) (28)
Materials and supplies 15 (50)
Accounts and wages payable (217) (176)
Taxes accrued 214 265
Assets, other (16) 5
Liabilities, other 17 (33)
----- -----
Net cash provided by operating activities 733 723
----- -----
Cash Flows From Investing:
Construction expenditures (565) (812)
Allowance for funds used during construction 7 14
Nuclear fuel expenditures (25) (15)
Other 1 -
----- -----
Net cash used in investing activities (582) (813)
----- -----
Cash Flows From Financing:
Dividends on common stock (279) (261)
Capital issuance costs (35) -
Redemptions:
Nuclear fuel lease - (64)
Short-term debt (635) -
Long-term debt (158) (30)
Preferred stock (41) -
Issuances:
Common stock 635 12
Nuclear fuel lease 31 3
Short-term debt - 255
Long-term debt 893 161
----- -----
Net cash provided by financing activities 411 76
----- -----
Net change in cash and cash equivalents 562 (14)
Cash and cash equivalents at beginning of year 67 126
----- -----
Cash and cash equivalents at end of period $ 629 $ 112
===== =====
Cash paid during the periods:
Interest $ 142 $ 123
Income taxes, net 111 78
See Notes to Consolidated Financial Statements.
4
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS' EQUITY
(Unaudited, in millions)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -----------------
2002 2001 2002 2001
------- ------ ------ -------
Common stock
Beginning balance $ 1 $ 1 $ 1 $ 1
Shares issued 1 - 1 -
------- ------ ------ -------
2 1 2 1
------- ------ ------ -------
Other paid-in capital
Beginning balance 1,826 1,581 1,614 1,581
Shares issued (less issuance costs of $11, $ -, $20, and $ -,
respectively) 354 12 614 12
Contracted stock purchase payment obligations - - (46) -
Employee stock awards - - (2) -
------- ------- ------ -------
2,180 1,593 2,180 1,593
------- ------- ------ -------
Retained earnings
Beginning balance 1,725 1,593 1,733 1,614
Net income 240 267 414 420
Dividends (97) (87) (279) (261)
------- ------- ------- -------
1,868 1,773 1,868 1,773
------- ------- ------- -------
Accumulated other comprehensive income
Beginning balance 3 (6) 5 -
Change in current period (see below) 4 1 2 (5)
------- ------- ------- -------
7 (5) 7 (5)
------- ------- ------- -------
Other
Beginning balance (10) (5) (4) -
Restricted stock compensation awards - - (7) (5)
Compensation amortized and mark-to-market adjustments - - 1 -
------- ------- ------- -------
(10) (5) (10) (5)
------- ------- ------- -------
Total common stockholders' equity $ 4,047 $ 3,357 $ 4,047 $ 3,357
======= ======= ======= =======
Comprehensive income, net of taxes
Net income $ 240 $ 267 $ 414 $ 420
Unrealized net gain/(loss) on derivative hedging instruments
(net of income taxes of $3, $-, $4 and $(2), respectively) 3 - 4 (3)
Reclassification adjustments for gains/(losses) included
in net income (net of income taxes of $ -, $2, $(2) and $7,
respectively) 1 1 (2) 9
Cumulative effect of accounting change, net of income taxes of
$(7) - - - (11)
------- ------- ------- -------
Total comprehensive income, net of taxes $ 244 $ 268 $ 416 $ 415
======= ======= ======= =======
- ------------------------------------------------------------------------------------------------------------
Common stock shares at beginning of period 144.8 137.2 138.0 137.2
Shares issued for financing purposes 8.0 - 13.8 -
Shares issued for dividend reinvestment and stock purchase plan
and 401K plans 0.7 - 1.7 -
------- ------- ------- -------
Common stock shares at end of period 153.5 137.2 153.5 137.2
======= ======= ======= =======
See Notes to Consolidated Financial Statements.
5
AMEREN CORPORATION
NOTES TO CONSOLIDATED 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 Ameren, our, we or us, we are referring to Ameren
Corporation on a consolidated basis. In certain circumstances, our subsidiaries
are specifically referenced in order to distinguish among their different
business activities. All tabular dollar amounts are in millions, unless
otherwise indicated.
Earnings Per Share
The calculation of earnings per share resulted in dilution of $.01 for the
quarter and nine months ended September 30, 2002. There was no dilution in the
prior year periods. The reconciling item in each of the periods was assumed
stock option conversions, which increased the number of shares outstanding in
the diluted earnings per share calculation by 340,210 shares for the three
months ended September 30, 2002 (2001 - 296,137) and 345,650 shares for the nine
months ended September 30, 2002 (2001 - 339,714).
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 $7
million, after taxes, to the income statement, and a cumulative effect
adjustment of $11 million after taxes to Accumulated Other Comprehensive Income
(OCI), which reduced common stockholders' 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. SFAS No. 141 and
SFAS No. 142 will be utilized for our acquisition of CILCORP Inc. and AES Medina
Valley (No. 4), L.L.C. 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 Ameren 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 at our regulated subsidiary, Union Electric Company,
operating as AmerenUE.
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
6
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 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 and in Operating
Expenses - Operations. 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 stockholders' equity. The following table
summarizes the impact of applying EITF Issue 02-3 on 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 $1,355 $1,432 $3,581 $3,513
Costs reclassified 123 10 243 10
- --------------------------------------------------------------------------------
Net operating revenues reported $1,232 $1,422 $3,338 $3,503
- --------------------------------------------------------------------------------
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 $106
million for the three months ended September 30, 2002 (2001 - $300 million) and
$477 million for the nine months ended September 30, 2002 (2001 - $691 million).
7
Purchased Power
Purchased power included in Operating Expenses - Operations - Fuel and
Purchased Power was $85 million for the three months ended September 30, 2002
(2001 - $295 million) and $420 million for the nine months ended September 30,
2002 (2001 - $670 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 $38 million (2001- $36 million) and
$94 million (2001 - $89 million), respectively. Excise taxes applicable to
Illinois electric customer bills are imposed on the consumer and are recorded as
tax collections payable.
Employee Benefit Plans
We made cash contributions totaling $15 million to our defined benefit
retirement plans during the third quarter of 2002 and we expect to make
additional cash contributions to the plans totaling approximately $15 million in
the fourth quarter of 2002. Future funding plans will be evaluated at the end of
2002. Based on the performance of plan assets through September 30, 2002, we
expect 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. 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
stockholders' 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, our subsidiary, AmerenUE, 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 AmerenUE's experimental alternative
regulation plan for its Missouri retail electric customers expired, the Missouri
Public Service Commission (MoPSC) Staff filed an excess earnings complaint
against AmerenUE with the MoPSC in July 2001. In March 2002, the MoPSC Staff
filed a recommendation that AmerenUE reduce its 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 AmerenUE's depreciation rates and other cost of service
adjustments. In May 2002, AmerenUE 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 AmerenUE's
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
8
AmerenUE's 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
AmerenUE's 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 AmerenUE of approximately 400 to 500
megawatts of generation assets from our non-regulated generation
subsidiary, 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 investment 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 AmerenUE's 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 AmerenUE's 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, or 22 cents per share. Net earnings are expected to be
reduced in 2002 due to the rate reduction ($26 million, net of taxes, or 18
cents per share), the expensing in the quarter ended June 30, 2002 of the entire
obligation to fund certain programs ($15 million, net of taxes, or 10 cents per
share), offset, in part, by the reduction in depreciation expense ($9 million,
net of taxes, or 6 cents per share). Net earnings were reduced due to the
stipulation and agreement by $11 million, or 7 cents per share, in the quarter
ended September 30, 2002 and by $20 million, or 14 cents per share, in the
quarter ended June 30, 2002.
In order to satisfy AmerenUE's regulatory load requirements for 2001,
AmerenUE purchased, under a one year contract (the 2001 Marketing Company -
AmerenUE agreement), 450 megawatts of capacity and energy from another of our
subsidiaries, AmerenEnergy Marketing Company (Marketing Company). This agreement
was entered into through a competitive bidding process and reflected
market-based rates. For 2002, AmerenUE 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, AmerenUE 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 AmerenUE 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 AmerenUE 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 AmerenUE from
completing the purchases contemplated by the 2001 and 2002 Marketing Company -
AmerenUE agreement 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.
9
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 establishing 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 AmerenUE 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 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. As
a result of the extension through January 1, 2007 of the electric rate freeze
related to the Illinois Law, we expect to seek to renew or extend a power supply
agreement between our Illinois-based utility subsidiary, Central Illinois Public
Service Company, operating as AmerenCIPS, and Marketing Company through the same
period. A renewal or extension of the power supply agreement will depend on
compliance with regulatory requirements in effect at the time, and we cannot
predict whether we will be successful in securing a renewal or extension of this
agreement. 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, AmerenUE and AmerenCIPS 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 either AmerenUE
or AmerenCIPS.
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, our subsidiaries, AmerenUE and
AmerenCIPS, along with several other utilities, were seeking approval from the
FERC to participate in an RTO known as the Alliance RTO. The Ameren companies
had previously been members of the Midwest Independent System Operator (Midwest
ISO) and recorded a pretax charge to earnings in 2000 of $25 million ($15
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
10
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
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 fee paid by the Ameren companies to leave the
Midwest ISO, provided the Ameren companies 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, Ameren made filings with the FERC
indicating that Ameren would return to the Midwest ISO through a new independent
transmission company, GridAmerica LLC, that was agreed to be formed by
AmerenCIPS and AmerenUE, and 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 us and other market participants in previous
filings.
Until the reliability and rate-barrier issues are resolved as ordered by
the FERC, and the tariffs and other material terms of our participation in
GridAmerica, and GridAmerica's participation in the Midwest ISO, are finalized
and approved by the FERC, we are unable to predict whether we 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 the 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 - 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.
11
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 $12 million in Other Assets and the fair value of
derivative financial instrument liabilities of $7 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.
The pretax net gain or loss on power forward derivative instruments, which
represented the impact of discontinued cash flow hedges, the ineffective portion
of cash flow hedges, as well as the reversal of amounts previously recorded in
OCI due to transactions going to delivery or settlement, was approximately a $5
million loss for the three months and a $4 million loss for the nine months
ended September 30, 2002. For the three and nine months ended September 30,
2001, the above related amounts were a $13 million gain in each period.
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).
As of September 30, 2002, a gain of approximately $5 million ($3 million,
net of taxes) associated with interest rate swaps was included in OCI. The swaps
were a partial hedge of the interest rate on debt that was issued in June 2002.
The swaps covered the first ten years of debt that has a 30-year maturity and
the gain in OCI is being amortized over a ten-year period beginning in June
2002.
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
Revenues, while the net change in the market value of coal, heating oil and
electricity options is recorded
12
as Operating Expense - 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 a gain of $4 million ($3
million, net of taxes) for the nine months ended September 30, 2002. For the
three and nine months ended September 30, 2001, the above related items were a
loss of $6 million ($4 million, net of taxes) in each period.
NOTE 4 - Debt and Equity Financings
In January 2002, Ameren Corporation issued $100 million of 5.70% notes due
February 1, 2007. The net proceeds were used to reduce short-term borrowings.
Interest is payable semi-annually on February 1 and August 1 of each year. In
March 2002, Ameren Corporation entered into interest rate swaps effectively
converting the interest rate associated with these notes to three month LIBOR
plus 43 basis points. At September 30, 2002, the effective interest rate for
these notes was 2.248%.
In March 2002, Ameren Corporation issued $345 million of adjustable
conversion-rate equity security units and $227 million of common stock
(5,000,000 shares at $39.50 per share and 750,000 shares, pursuant to the
exercise of an option granted to the underwriters, at $38.865 per share). The
$25 adjustable conversion-rate equity security units each consisted of an Ameren
Corporation senior unsecured note with a principal amount of $25 and a contract
to purchase, for $25, a fraction of a share of Ameren common stock on May 15,
2005. The senior unsecured notes were recorded at their fair value of $345
million and will mature on May 15, 2007. Total distributions on the equity
security units will be at an annual rate of 9.75%, consisting of quarterly
interest payments on the senior unsecured notes at the initial annual rate of
5.20% and adjustment payments under the stock purchase contracts at the annual
rate of 4.55%. The stock purchase contracts require holders to purchase between
8.7 million and 7.4 million shares of Ameren common stock on May 15, 2005 at the
market price at that time, subject to a minimum share price of $39.50 and a
maximum of $46.61. The stock purchase contracts include a pledge of the senior
unsecured notes as collateral for the stock purchase obligation. The interest
rate on the outstanding senior unsecured notes is subject to being reset by a
remarketing agent for quarterly payments after May 15, 2005 until maturity. We
recorded the net present value of the contracted stock purchase adjustment
payments of $46 million as an increase in Other Deferred Credits and Liabilities
to reflect our obligation and a decrease in Other Paid-in Capital to reflect the
fair value of the stock purchase contract. The liability for the contracted
stock purchase adjustment payments will be reduced as such payments are made
through May 15, 2005. We used the net proceeds from these offerings to repay our
short-term indebtedness and for general corporate purposes.
In June 2002, Generating Company issued $275 million of 7.95% Senior Notes
due June 1, 2032. Interest is payable semi-annually on June 1 and December 1 of
each year, beginning December 1, 2002. Generating Company received net proceeds
of $271 million, after debt discount and underwriters' fees, that were used to
reduce short-term borrowings incurred to finance previous generating capacity
additions and for general corporate purposes.
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 our commercial paper programs. The $400 million
in new facilities includes a $270 million 364-day revolving credit facility and
a $130 million 3-year revolving credit facility. The 3-year facility has a $50
million sub-limit for the issuance of letters of credit. These new credit
facilities replaced AmerenUE's $300 million revolving credit facility. At
September 30, 2002, all of such borrowing capacity under these new facilities
was available.
In August 2002, AmerenUE 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 AmerenUE's first mortgage bonds until the
release date as described in the senior secured note indenture. Proceeds were
used to redeem, in September 2002, AmerenUE's $125 million principal amount
8.75% first mortgage bonds due December 1, 2021 at a 4.38% premium and
AmerenUE's $41 million $1.735 series preferred stock at par.
13
In September 2002, Ameren Corporation issued $338 million of common stock
(8,050,000 shares at $42.00 per share, including 1,050,000 shares pursuant to
the exercise of an option granted to the underwriters). Net proceeds were $327
million after underwriters' fees. We anticipate using the net proceeds from this
offering to fund part of the cash portion of the purchase price for our
acquisition of CILCORP Inc. (see Note 7 - "CILCORP Acquisition") and for general
corporate purposes. Pending such uses, we are investing the net proceeds in
short-term instruments.
Amortization of debt issuance costs and premium/discount for the three and
nine months ending September 30, 2002 of $2 million (2001 - $1 million) and $6
million (2001 - $4 million) were included in interest expense in the income
statement.
NOTE 5 - 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 $ 4 $ - $ 6 $ 1
Gain on disposition of property - 1 3 2
Other 1 9 4 11
- --------------------------------------------------------------------------------
Total miscellaneous income $ 5 $10 $13 $14
- --------------------------------------------------------------------------------
Miscellaneous expense:
Minority interest in subsidiary $ (2) $(1) $(13) $(3)
Loss on disposition of property - - - (2)
Donations - rate settlement - - (26) (1)
Other (1) (2) (7) (5)
- --------------------------------------------------------------------------------
Total miscellaneous expense $ (3) $(3) $(46) $(11)
- --------------------------------------------------------------------------------
NOTE 6 - Segment Information
Segment information for the three and nine months ended September 30, 2002
and 2001 was as follows:
- --------------------------------------------------------------------------------
Utility Intercompany
Operations Other Revenues Total
- --------------------------------------------------------------------------------
Three months ended September 30, 2002:
Revenues $1,368 $87 $(223) $1,232
Net income 238 2 - 240
- --------------------------------------------------------------------------------
Three months ended September 30, 2001:
Revenues $1,619 $60 $(257) $1,422
Net income 267 - - 267
- --------------------------------------------------------------------------------
14
Nine months ended September 30, 2002:
Revenues $3,663 $262 $(587) $3,338
Net income 397 17 - 414
- --------------------------------------------------------------------------------
Nine months ended September 30, 2001:
Revenues $3,952 $193 $(642) $3,503
Net income 419 1 - 420
- --------------------------------------------------------------------------------
Ameren Services Company, which provides shared support services to us and
our subsidiaries, allocates administrative support services to each segment
based on various factors, such as headcount, number of customers, and total
assets.
NOTE 7 - CILCORP Acquisition
On April 28, 2002, we 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. We 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. We expect 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 FERC, the SEC under PUHCA, 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. We do not expect that
this extension will impact the anticipated transaction closing date. In October
2002, we 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, we have 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.
15
NOTE 8 - Subsequent Event
On November 4, 2002, we announced a voluntary retirement program that is
being offered to approximately 1,000 of our 7,400 employees. In addition, we
announced limits on our contributions and 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 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 could range between $30 million and
$50 million, based on voluntary retirements ranging between 300 and 500,
respectively. In addition to the voluntary retirement program, we 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, the company will continue to seek other
ways to reduce staffing over the next year to reduce costs and gain efficiencies
in operations.
16
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
OVERVIEW
Ameren Corporation is a holding company registered under the Public Utility
Holding Company Act of 1935 (PUHCA). Our 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. Our primary subsidiaries are as follows:
o Union Electric Company, which operates a regulated electric generation,
transmission and distribution business, and a regulated natural gas
distribution business in Missouri and Illinois as AmerenUE.
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 our 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 our affiliated companies.
o AmerenEnergy, Inc. (AmerenEnergy) which serves as a power marketing and
risk management agent for our 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 60% ownership interest
in EEI and consolidate it for financial reporting purposes.
o Ameren Services Company, which provides shared support services to us and
our subsidiaries.
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 incorporated by
reference from our Annual Report to Stockholders 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 is incorporated by reference from our Annual Report to
Stockholders in our Annual Report on Form 10-K for the year ended December
31, 2001.
When we refer to Ameren, our, we or us, we are referring to Ameren
Corporation on a consolidated basis. In certain circumstances, our subsidiaries
are specifically referenced in order to distinguish among their different
business activities. 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 approximately 85% 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.
17
RESULTS OF OPERATIONS
Summary
Our net income decreased $27 million to $240 million, or $1.64 per share
($1.63 per share diluted), in the third quarter of 2002 from $267 million, or
$1.94 per share, in the third quarter of 2001. Earnings for the nine months
ended September 30, 2002 totaled $414 million, or $2.88 per share ($2.87 per
share diluted), compared to the year-ago earnings of $420 million, or $3.06 per
share. The decrease in both periods in 2002 was primarily due to the impact of
the settlement of our Missouri electric rate case (third quarter - 7 cents per
share; year to date - 21 cents per share), increased costs of employee benefits
(third quarter - 4 cents per share; year to date - 11 cents per share), higher
depreciation, and a decline in industrial sales due to the continued soft
economy. Increased average shares outstanding (third quarter - 9.5 million
shares; year to date - 6.4 million shares) and financing costs reduced earnings
per share in 2002 by approximately 14 cents in the third quarter and 20 cents
year to date. The nine-month period comparison was also affected by a reduction
of the accrual in 2001 for expected customer sharing credits under the Missouri
electric experimental alternative regulation plan that expired in June 2001 (see
Note 2 - "Rate and Regulatory Matters" to our consolidated financial
statements).
The decreases in both periods were partially offset by favorable weather
conditions (third quarter - 11 cents per share; year to date - 14 cents per
share). The nine-month period in 2002 was also favorably affected by increased
sales of emission credits, including such sales by EEI (12 cents per share) and
the lack of a Callaway nuclear plant refueling outage to date in 2002 (14 cents
per share). In January 2001, we recorded a charge of $7 million, or five cents
per share, due to the adoption of Statement of Financial Accounting Standards
(SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities."
As a holding company, our net income and cash flows are primarily generated
by our principal operating subsidiaries, AmerenUE, AmerenCIPS and AmerenEnergy
Generating Company. These subsidiaries also file quarterly and annual reports
with the Securities and Exchange Commission. The contribution by our principal
operating subsidiaries to net income for the three and nine months ended
September 30, 2002 was as follows:
- --------------------------------------------------------------------------------
Three Months Nine Months
- --------------------------------------------------------------------------------
2002 2001 2002 2001
---- ---- ---- ----
Primarily rate-regulated operations
AmerenUE (a) $204 $201 $358 $317
AmerenCIPS 23 24 31 43
- --------------------------------------------------------------------------------
$227 $225 $389 $360
- --------------------------------------------------------------------------------
Primarily non rate-regulated operations
AmerenEnergy Generating (a)(b) 15 43 31 68
Other (2) (1) (6) (8)
- --------------------------------------------------------------------------------
Ameren net income $240 $267 $414 $420
- --------------------------------------------------------------------------------
(a) includes earnings from interchange sales by AmerenEnergy.
(b) includes earnings from contract to supply power to AmerenCIPS customers.
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 employees in early
November 2002 and is expected to result in a fourth quarter 2002 after-tax
charge of between $30 million and $50 million.
18
Missouri Electric Rate Case
From July 1, 1995 through June 30, 2001, our subsidiary, AmerenUE, 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 AmerenUE's experimental alternative
regulation plan for its Missouri retail electric customers expired, the Missouri
Public Service Commission (MoPSC) Staff filed an excess earnings complaint
against AmerenUE with the MoPSC in July 2001. In March 2002, the MoPSC Staff
filed a recommendation that AmerenUE reduce its 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 AmerenUE's depreciation rates and other cost of service
adjustments. In May 2002, AmerenUE 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 AmerenUE's
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 AmerenUE's 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
AmerenUE's 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 AmerenUE of approximately 400 to 500
megawatts of generation assets from our non-regulated generation
subsidiary, 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 investment 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 AmerenUE's 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 AmerenUE's 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, or 22 cents per share. Net earnings are expected to be
reduced in 2002 due to the rate reduction ($26 million, net of taxes, or 18
cents per share), the expensing in the quarter ended June 30, 2002 of the entire
obligation to fund certain programs ($15 million, net of taxes, or 10 cents per
share), offset, in part, by the reduction in depreciation expense ($9 million,
net of taxes, 6 cents per share). Net earnings were reduced due to the
stipulation and agreement by $11 million, or 7 cents per share, in the quarter
ended September 30, 2002 and by $20 million, or 14 cents per share, in the
quarter ended June 30, 2002.
19
CILCORP Acquisition
On April 28, 2002, we 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. We 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. We expect 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 Federal Energy Regulatory Commission
(FERC), the Securities and Exchange Commission (SEC) under PUHCA, 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. We do not expect that this extension will impact the
anticipated transaction closing date. In October 2002, we 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 we have agreed to invest approximately
$23 million by December 31, 2008 to increase the power import capability into
CILCO' 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.
In April 2002, as a result of AmerenUE's 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. 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
20
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 months ended September 30, 2002 from the comparable periods
in 2001:
- --------------------------------------------------------------------------------
Three Months Nine Months
- --------------------------------------------------------------------------------
Operating Revenues:
Effect of abnormal weather (estimate) $ 47 $ 58
Growth and other (estimate) (34) 16
Rate reductions (23) (36)
Credit to customers - (10)
Interchange revenues (194) (214)
EEI 25 77
- --------------------------------------------------------------------------------
(179) (109)
- --------------------------------------------------------------------------------
Fuel and Purchased Power:
Fuel:
Generation (15) (37)
Price 3 11
Generation efficiencies and other (2) (2)
Purchased power 210 250
EEI (26) (44)
- --------------------------------------------------------------------------------
170 178
- --------------------------------------------------------------------------------
Change in electric margin $ (9) $ 69
- --------------------------------------------------------------------------------
Electric margin decreased $9 million for the three months ended September
30, 2002, but increased $69 million for the nine months ended September 30, 2002
compared to the same year-ago periods. Increases in margin for the nine-month
period were primarily attributable to more favorable weather conditions,
increased sales of emission credits, lack of a Callaway nuclear plant refueling
outage to date in 2002, and lower fuel costs. Our region also experienced
favorable weather conditions during the third quarter of 2002. Weather-sensitive
residential electric kilowatt-hour sales in 2002 increased by 9% in the third
quarter and 5% for the year to date, and commercial electric kilowatt-hour sales
increased by 4% in the quarter and 2% for the year to date. Industrial sales
were 3% lower in the third quarter and 6% lower in the first nine months of 2002
as compared to 2001 due primarily to the impact of the soft economy. The third
quarter of 2001 benefited from emission sales of $9 million and a FAS 133 gain
of $3 million (2002 - loss of $4 million). Revenues were reduced by $23 million
for the three months 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. Contribution to electric
margin from EEI increased in the nine-month period of 2002 principally due to
EEI's sale of $38 million in emission credits. Interchange revenues decreased
due 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 was reduced in the first nine months of 2002 due to
lower interchange sales and the lack of a Callaway refueling, partially offset
by unscheduled coal plant outages. Another refueling outage at Callaway began in
mid-October which is expected to last 35 days and is estimated to reduce fourth
quarter 2002 earnings by 9 cents per share.
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 our consolidated
financial statements).
21
Gas Operations
Our gas margins decreased $6 million in the third quarter of 2002 as
compared to the same period in 2001 with revenues decreasing by $10 million and
costs decreasing by $4 million. The prior year third quarter included the
benefit of the recovery of gas costs from our customers under a purchased gas
adjustment clause. Warmer winter weather early in 2002 resulted in margins for
the first nine months of 2002 being $10 million below the year-ago period. Gas
revenues decreased $53 million, and gas costs decreased $43 million in the first
nine months of 2002 as compared to the year-ago period primarily due to lower
natural gas prices and the warmer winter.
Other Operating Expenses
Operating Expenses - Operations - Other increased $24 million in the third
quarter and $49 million in the first nine months of 2002 compared to the prior
year periods, primarily due to higher employee benefit costs related to the
investment performance of pension plan assets and increasing healthcare costs.
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.
Maintenance expenses increased $3 million in the third quarter of 2002, but
decreased $28 million in the first nine months of 2002, compared to the prior
year periods. The decrease for the nine months ended September 30, 2002 was
primarily due to the lack of a Callaway refueling outage in the first nine
months of 2002.
Depreciation and amortization expenses increased $4 million in the third
quarter of 2002 and $18 million in the first nine months of 2002, compared to
the year-ago periods. This net increase was primarily due to our investment in
coal power plants and combustion turbine electric generating plants. The
increase in 2002 was partially offset by a reduction of depreciation rates based
on an updated analysis of asset values, service lives and accumulated
depreciation levels and agreed to in the stipulation and agreement associated
with the Missouri electric rate case (third quarter - $5 million; year to date -
$10 million).
Income tax expense decreased $35 million in the third quarter of 2002 and
$34 million in the first nine months of 2002, compared to the year-ago periods,
primarily due to lower pretax income. Income taxes related to our non-regulated
operations are recorded in Other Income and Deductions.
Other taxes expense decreased $1 million in the third quarter of 2002, but
increased $8 million in the first nine months of 2002, compared to the year-ago
periods. The increase for the nine months was primarily due to higher gross
receipts taxes resulting from increased electric sales in 2002 and adjustments
related to revised property tax assessments in the prior year.
Other Income and Deductions
Other income and deductions (excluding income taxes) decreased $8 million
in the third quarter of 2002 and $41 million in the first nine months of 2002,
compared to the same periods last year. The decrease for the nine-month period
was primarily due to the commitment to fund certain programs as part of the
settlement of the Missouri electric rate case ($26 million), and an increase in
the minority interest principally related to EEI's sale of emission credits ($10
million). See Note 5 - "Miscellaneous, net" to our consolidated financial
statements.
Interest
Interest expense increased $6 million in the third quarter of 2002 and $13
million in the first nine months of 2002, compared to the year-ago periods,
primarily due to our issuance of $345 million of adjustable conversion rate
equity security units in March 2002 and Generating Company's issuance of $275
million of 7.95% notes in June 2002. A significant amount of the proceeds from
these offerings was used to repay lower cost short-term borrowings.
22
LIQUIDITY AND CAPITAL RESOURCES
Operating
Our cash flows provided by operating activities increased $10 million to
$733 million for the nine months ended September 30, 2002, compared to the
year-ago period. Cash provided from operations increased primarily as a result
of favorable weather and a net decrease in materials and supplies primarily
associated with decreased coal inventories and gas storage. Materials and
supplies were higher than normal at December 31, 2001, due to the warm winter
and anticipation of a potential coal supply disruption that ultimately did not
occur. These increases were partially offset by payments of customer sharing
credits under AmerenUE's now-expired electric alternative regulation plan, lower
rates associated with our Missouri rate case settlement, and timing of payments
on accounts payable and accrued taxes.
The tariff-based gross margins of our utility operating companies 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. Ameren is authorized by the
SEC under PUHCA to have up to an aggregate $2.8 billion of short-term unsecured
debt instruments outstanding at any one time. Short-term borrowings consist of
commercial paper (maturities generally within 1 to 45 days) and bank loans. At
September 30, 2002, Ameren had bank credit agreements, expiring at various dates
during 2002 and 2003, which supported commercial paper programs totaling $830
million, of which $400 million was for the use by us and any of our wholly-owned
subsidiaries, and the remaining $430 million was for use by our regulated
subsidiaries. At September 30, 2002, all $830 million of such borrowing capacity
was available. At September 30, 2002, we also had committed bank lines of credit
aggregating $71 million not supporting commercial paper programs, all of which
were unused and available at such date for use by us and any of our wholly-owned
subsidiaries. There were no borrowings under these agreements as of September
30, 2002.
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 our commercial paper programs, all of which was
available as of September 30, 2002. 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
AmerenUE's $300 million revolving credit facility that was in place as of June
30, 2002. Ameren Corporation has a $200 million revolving credit facility which
will mature in December 2002. We expect to replace these various bank credit
agreements prior to their maturity. These bank facilities make available interim
financing at various rates of interest based on LIBOR, the bank certificate of
deposit rate or other options.
AmerenUE also has 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, Ameren and its subsidiaries were
in compliance with these provisions.
At September 30, 2002, neither Ameren, nor any of its subsidiaries, had any
off-balance sheet financing arrangements.
We made cash contributions totaling $15 million to our defined benefit
retirement plans during the third quarter of 2002 and we expect to make
additional cash contributions to the plans totaling approximately $15 million in
the fourth quarter of 2002. Future funding plans will be evaluated at the end of
2002. Based on the performance of plan assets through September 30, 2002, we
expect 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. These amounts are estimates
and may change based on actual stock market performance, changes in interest
rates, any plan
23
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 stockholders' 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 $582 million in the first
nine months of 2002 compared to $813 million in the first nine months of 2001.
In the first nine months of 2002, construction expenditures were $419 million
(2001 - $468 million) in our regulated operations, primarily related to various
upgrades at our coal power plants and further construction of combustion turbine
generating units, and $146 million (2001 - $344 million) in our non-regulated
operations, primarily related to the construction of combustion turbine
generating units. In the first nine months of 2002, we placed into service 240
megawatts of combustion turbine electric generation capacity in our regulated
operations and 351 megawatts in our non-regulated operations. Regulated capital
expenditures are expected to approximate $170 million and non-regulated capital
expenditures are expected to approximate $40 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 consolidated financial
statements), AmerenUE 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 AmerenUE's
Callaway nuclear power plant. The 700 megawatts of new generation includes 240
megawatts already added this year, as well as the proposed transfer of
approximately 400 to 500 megawatts of generation assets to AmerenUE from
Generating Company. The transfer, which is subject to necessary regulatory
approvals, is expected to be completed in the second quarter of 2003.
Ameren completed construction of one combustion turbine generating unit at
Elgin, Illinois during the third quarter of 2002 and two additional units in
October 2002. The total installed cost of these three units was approximately
$156 million representing 351 megawatts of capacity. Ameren expects to complete
construction of an additional unit at Elgin by the end of 2002, which is planned
to provide 117 megawatts of additional capacity at a cost of approximately $50
million. The Elgin facility will be owned by Ameren's non-regulated subsidiary,
Generating Company.
As of September 30, 2002, Resources Company had invested $28 million in a
117 megawatt combustion turbine generating unit originally planned for
installation in 2002. We are evaluating using this unit within Ameren's power
system in the future or selling it to a third party.
Due to expected increased demand and the need to maintain appropriate power
reserve margins, Ameren believes AmerenUE will need additional generating
capacity in the future. We have an equipment supply agreement in place at
AmerenUE 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.
Ameren continually reviews its 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 Ameren may plan to make for future generating needs could result in losses
being incurred, which could be material.
Financing
Our cash flows provided by financing activities totaled $411 million in the
first nine months of 2002, compared to $76 million in the year-ago period. Our
principal financing activities for the period included the issuance of long-term
debt, equity security units and common stock, partially offset by redemptions of
short-term debt, long-term debt, and preferred stock, as well as payments of
dividends.
24
In January 2002, Ameren Corporation issued $100 million of 5.70% notes due
February 1, 2007. The net proceeds were used to reduce short-term borrowings.
Interest is payable semi-annually on February 1 and August 1 of each year. In
March 2002, Ameren Corporation entered into interest rate swaps effectively
converting the interest rate associated with these notes to three month LIBOR
plus 43 basis points. At September 30, 2002, the effective interest rate for
these notes was 2.248%.
In March 2002, Ameren Corporation issued $345 million of adjustable
conversion-rate equity security units and $227 million of common stock
(5,000,000 shares at $39.50 per share and 750,000 shares, pursuant to the
exercise of an option granted to the underwriters, at $38.865 per share). The
$25 adjustable conversion-rate equity security units each consisted of an Ameren
Corporation senior unsecured note with a principal amount of $25 and a contract
to purchase, for $25, a fraction of a share of Ameren common stock on May 15,
2005. The senior unsecured notes were recorded at their fair value of $345
million and will mature on May 15, 2007. Total distributions on the equity
security units will be at an annual rate of 9.75%, consisting of quarterly
interest payments on the senior unsecured notes at the initial annual rate of
5.20% and adjustment payments under the stock purchase contracts at the annual
rate of 4.55%. The stock purchase contracts require holders to purchase between
8.7 million and 7.4 million shares of Ameren common stock on May 15, 2005 at the
market price at that time, subject to a minimum share price of $39.50 and a
maximum of $46.61. The stock purchase contracts include a pledge of the senior
unsecured notes as collateral for the stock purchase obligation. The interest
rate on the outstanding senior unsecured notes is subject to being reset by a
remarketing agent for quarterly payments after May 15, 2005 until maturity. We
recorded the net present value of the contracted stock purchase payments of $46
million as an increase in Other Deferred Credits and Liabilities to reflect our
obligation and a decrease in Other Paid-in Capital to reflect the fair value of
the stock purchase contract. The liability for the contracted stock purchase
adjustment payments will be reduced as such payments are made through May 15,
2005. We used the net proceeds from these offerings to repay our short-term
indebtedness and for general corporate purposes.
In May 2002, AmerenUE 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, and 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 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 AmerenUE's first mortgage bonds until the release date as described in the
senior secured note indenture. Proceeds were used to redeem, in September 2002,
AmerenUE's $125 million principal amount 8.75% first mortgage bonds due December
1, 2021 at a 4.38% premium and AmerenUE's $41 million $1.735 series 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.
In June 2002, Ameren Corporation filed a shelf registration statement with
the SEC on Form S-3 authorizing the offering from time to time of up to $1.473
billion of various forms of securities including long-term debt, trust preferred
and equity securities to finance ongoing construction and maintenance programs,
to redeem, repurchase, repay, or retire outstanding debt, to finance strategic
investments, including our pending acquisition of CILCORP Inc., and for general
corporate purposes. The SEC declared the registration statement effective in
August 2002.
In September 2002, Ameren Corporation issued, pursuant to the shelf
registration statement, $338 million of common stock (8,050,000 shares at $42.00
per share, including 1,050,000 shares pursuant to the exercise of an option
granted to the underwriters). Net proceeds were $327 million after underwriters'
fees. We anticipate using the net proceeds from this offering to fund part of
the cash portion of the purchase price for our acquisition of CILCORP Inc. (see
Note 7 - "CILCORP Acquisition" to our consolidated financial statements) and for
general corporate purposes. Pending such uses, we are investing the net proceeds
in short-term instruments. The proceeds from this financing along with existing
credit
25
lines are expected to be adequate to fund the completion of the CILCORP
acquisition. However, within one year of the completion of the acquisition, we
believe we will need to issue additional common stock to provide proceeds of up
to $150 million to $175 million in order to permanently fund the cash portion of
the purchase price. 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.
In June 2002, Generating Company issued $275 million of 7.95% Senior Note