UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For Quarterly Period Ended June 30, 2003
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For The Transition Period From to
Commission file number 1-14756.
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 ( ).
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes (X). No ( ).
Shares outstanding of each of the registrant's classes of common stock as
of August 11, 2003: Common Stock, $.01 par value - 161,799,616.
AMEREN CORPORATION
TABLE OF CONTENTS
Page
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PART I. Financial Information
ITEM 1. Financial Statements (Unaudited)
Consolidated Balance Sheet at June 30, 2003 and December 31, 2002................................ 2
Consolidated Statement of Income for the three and six months ended June 30, 2003 and 2002....... 3
Consolidated Statement of Cash Flows for the six months ended June 30, 2003 and 2002............. 4
Consolidated Statement of Common Stockholders' Equity for the three and six months ended June 30,
2003 and 2002.................................................................................... 5
Notes to Consolidated Financial Statements....................................................... 6
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations............ 19
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk....................................... 29
ITEM 4. Controls and Procedures.......................................................................... 32
Forward-Looking Statements....................................................................... 32
PART II. Other Information
ITEM 1. Legal Proceedings................................................................................ 34
ITEM 4. Submission of Matters to a Vote of Security Holders.............................................. 35
ITEM 5. Other Information................................................................................ 35
ITEM 6. Exhibits and Reports on Form 8-K................................................................. 36
SIGNATURE.................................................................................................... 38
This Form 10-Q contains "forward-looking statements" within the meaning of
Section 21E of the Securities Exchange Act of 1934. Forward-looking
statements should be read with the cautionary statements and important
factors included in this Form 10-Q at Part I under the heading
"Forward-Looking Statements." Forward-looking statements are all statements
other than statements of historical fact, including those statements that
are identified by the use of the words "anticipates," "estimates,"
"expects," "intends," "plans," "predicts," "projects," and similar
expressions.
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements.
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(Unaudited, in millions, except per share amounts)
June 30, December 31,
2003 2002
-------- ------------
ASSETS:
Property and plant, net $ 10,197 $ 8,840
Investments and other assets:
Investments 168 38
Nuclear decommissioning trust fund 191 172
Goodwill and other intangibles, net 620 -
Other assets 313 307
--------- ---------
Total investments and other assets 1,292 517
--------- ---------
Current assets:
Cash and cash equivalents 101 628
Accounts receivable - trade (less allowance for doubtful
accounts of $9 and $7, respectively) 299 266
Unbilled revenue 257 176
Miscellaneous accounts and notes receivable 56 44
Materials and supplies, at average cost 420 299
Other current assets 44 39
--------- ---------
Total current assets 1,177 1,452
--------- ---------
Regulatory assets 791 690
--------- ---------
Total Assets $ 13,457 $ 11,499
========= =========
CAPITAL AND LIABILITIES:
Capitalization:
Common stock, $.01 par value, 400.0 shares authorized -
shares outstanding of 161.7 and 154.1, respectively $ 2 $ 2
Other paid-in capital, principally premium on common stock 2,500 2,203
Retained earnings 1,745 1,739
Accumulated other comprehensive income (loss) (100) (93)
Other (10) (9)
--------- ---------
Total common stockholders' equity 4,137 3,842
--------- ---------
Preferred stock not subject to mandatory redemption 213 193
Long-term debt, net 4,177 3,433
Preferred stock subject to mandatory redemption 22 -
--------- ---------
Total capitalization 8,549 7,468
--------- ---------
Minority interest in consolidated subsidiaries 19 15
Current liabilities:
Current maturities of long-term debt 407 339
Short-term debt 180 271
Accounts and wages payable 297 369
Asset retirement obligations 4 -
Taxes accrued 163 45
Other current liabilities 212 177
--------- ---------
Total current liabilities 1,263 1,201
--------- ---------
Accumulated deferred income taxes 1,964 1,707
Accumulated deferred investment tax credits 156 149
Regulatory liabilities 123 136
Asset retirement obligations 403 174
Accrued pension liabilities 539 377
Other deferred credits and liabilities 441 272
--------- ---------
Total Capital and Liabilities $ 13,457 $ 11,499
========= =========
See Notes to Consolidated Financial Statements.
2
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Unaudited, in millions, except per share amounts)
Three Months Ended Six Months Ended
June 30, June 30,
------------------ -------------------
2003 2002 2003 2002
------------------ -------------------
OPERATING REVENUES:
Electric $ 968 $ 930 $ 1,824 $ 1,677
Gas 118 47 368 172
Other 2 1 4 3
-------- -------- -------- --------
Total operating revenues 1,088 978 2,196 1,852
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel and purchased power 228 204 449 407
Gas 87 27 272 112
Other operations and maintenance 314 295 613 557
Depreciation and amortization 132 106 256 213
Income taxes 67 83 119 121
Other taxes 77 69 155 137
-------- -------- -------- --------
Total operating expenses 905 784 1,864 1,547
-------- -------- -------- --------
OPERATING INCOME 183 194 332 305
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction 1 - 1 2
Miscellaneous, net -
Miscellaneous income 5 5 11 8
Miscellaneous expense (8) (39) (11) (43)
Income taxes - 10 - 10
-------- -------- -------- --------
Total other income and (deductions) (2) (24) 1 (23)
-------- -------- -------- --------
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest 70 53 138 105
Allowance for borrowed funds used during construction (1) (1) (3) (3)
Preferred dividends of subsidiaries 2 3 5 6
-------- -------- -------- --------
Net interest charges and preferred dividends 71 55 140 108
-------- -------- -------- --------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 110 115 193 174
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES - - 18 -
-------- -------- -------- --------
NET INCOME $ 110 $ 115 $ 211 $ 174
======== ======== ======== ========
EARNINGS PER COMMON SHARE - BASIC AND DILUTED:
Income before cumulative effect of change
in accounting principle $ 0.68 $ 0.80 $ 1.21 $ 1.22
Cumulative effect of change in accounting
principle, net of income taxes - - 0.11 -
-------- -------- -------- --------
Net income $ 0.68 $ 0.80 $ 1.32 $ 1.22
======== ======== ======== ========
AVERAGE COMMON SHARES OUTSTANDING 161.2 144.4 160.1 142.1
See Notes to Consolidated Financial Statements.
3
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited, in millions)
Six Months Ended
June 30,
----------------
2003 2002
----- -----
Cash Flows From Operating:
Net income $ 211 $ 174
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting principle (18) -
Depreciation and amortization 256 213
Amortization of nuclear fuel 16 16
Amortization of debt issuance costs and premium/discounts 5 4
Allowance for funds used during construction (4) (5)
Deferred income taxes, net (9) (6)
Deferred investment tax credits, net (6) (4)
Other (7) -
Changes in assets and liabilities, excluding the effects of the acquisitions:
Receivables, net 6 (74)
Materials and supplies (14) 32
Accounts and wages payable (149) (139)
Taxes accrued 99 107
Assets, other 17 (12)
Liabilities, other 27 40
------ ------
Net cash provided by operating activities 430 346
------ ------
Cash Flows From Investing:
Construction expenditures (332) (401)
Acquisitions, net of cash acquired (489) -
Allowance for funds used during construction 4 5
Nuclear fuel expenditures (1) (16)
Other 2 1
------ ------
Net cash used in investing activities (816) (411)
------ ------
Cash Flows From Financing:
Dividends on common stock (205) (182)
Capital issuance costs (11) (23)
Redemptions:
Nuclear fuel lease (20) -
Short-term debt (91) (637)
Long-term debt (420) (5)
Issuances:
Common stock 308 269
Nuclear fuel lease - 6
Long-term debt 298 720
------ ------
Net cash provided by (used in) financing activities (141) 148
------ ------
Net change in cash and cash equivalents (527) 83
Cash and cash equivalents at beginning of year 628 67
------ ------
Cash and cash equivalents at end of period $ 101 $ 150
====== ======
Cash paid during the periods:
Interest $ 133 $ 99
Income taxes, net 100 77
See Notes to Consolidated Financial Statements.
4
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS' EQUITY
(Unaudited, in millions)
Three Months Ended Six Months Ended
June 30, June 30,
------------------ -------------------
2003 2002 2003 2002
-------- ------- -------- --------
Common stock
Beginning balance $ 2 $ 1 $ 2 $ 1
Shares issued - - - -
-------- -------- -------- --------
2 1 2 1
-------- -------- -------- --------
Other paid-in capital
Beginning balance 2,480 1,804 2,203 1,614
Shares issued (less issuance costs of $-, $-, $8 and $9, respectively) 23 23 300 260
Contracted stock purchase payment obligations - - - (46)
Employee stock awards (3) (1) (3) (2)
-------- -------- -------- --------
2,500 1,826 2,500 1,826
-------- -------- -------- --------
Retained earnings
Beginning balance 1,738 1,701 1,739 1,733
Net income 110 115 211 174
Dividends (103) (91) (205) (182)
-------- -------- -------- --------
1,745 1,725 1,745 1,725
-------- -------- -------- --------
Accumulated other comprehensive income (loss)
Beginning balance - derivative financial instruments 6 - 9 5
Change in derivative financial instruments in current period (4) 3 (7) (2)
-------- -------- -------- --------
2 3 2 3
-------- -------- -------- --------
Beginning balance - minimum pension liability (102) - (102) -
Change in minimum pension liability in current period - - - -
-------- -------- -------- --------
(102) - (102) -
-------- -------- -------- --------
(100) 3 (100) 3
-------- -------- -------- --------
Other
Beginning balance (14) (10) (9) (4)
Restricted stock compensation awards - - (5) (7)
Compensation amortized and mark-to-market adjustments 4 - 4 1
-------- -------- -------- --------
(10) (10) (10) (10)
-------- -------- -------- --------
Total common stockholders' equity $ 4,137 $ 3,545 $ 4,137 $ 3,545
======== ======== ======== ========
Comprehensive income, net of taxes
Net income $ 110 $ 115 $ 211 $ 174
Unrealized net gain/(loss) on derivative hedging instruments,
net of income taxes of $(2), $1, $(2) and $1, respectively (4) 2 (5) 1
Reclassification adjustments for gains/(losses) included in net income,
net of income taxes of $-, $-, $(1) and $(2), respectively - 1 (2) (3)
-------- -------- -------- --------
Total comprehensive income, net of taxes $ 106 $ 118 $ 204 $ 172
======== ======== ======== ========
- ----------------------------------------------------------------------------------------------------------------------
Common stock shares at beginning of period 161.1 144.2 154.1 138.0
Shares issued 0.6 0.6 7.6 6.8
-------- -------- -------- --------
Common stock shares at end of period 161.7 144.8 161.7 144.8
======== ======== ======== ========
See Notes to Consolidated Financial Statements.
5
AMEREN CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
June 30, 2003
NOTE 1 - Summary of Significant Accounting Policies
General
Ameren Corporation is a public utility holding company registered with
the Securities and Exchange Commission (SEC) under the Public Utility
Holding Company Act of 1935 (PUHCA) and is headquartered in St. Louis,
Missouri. 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 principal subsidiaries are as follows:
o Union Electric Company, which operates a rate-regulated electric
generation, transmission and distribution business, and a rate-regulated
natural gas distribution business in Missouri and Illinois as AmerenUE.
o Central Illinois Public Service Company, which operates a rate-regulated
electric and natural gas transmission and distribution business in Illinois
as AmerenCIPS.
o Central Illinois Light Company, a subsidiary of CILCORP Inc. (CILCORP),
which operates a rate-regulated electric transmission and distribution
business, an electric generation business, and a rate-regulated natural gas
distribution business in Illinois as AmerenCILCO. We completed our
acquisition of CILCORP on January 31, 2003. See Note 2 - Acquisitions for
further information.
o AmerenEnergy Resources Company (Resources Company), which consists of non
rate-regulated operations. Subsidiaries include AmerenEnergy Generating
Company (Generating Company), which operates our non rate-regulated
electric generation in Missouri and Illinois, AmerenEnergy Marketing
Company (Marketing Company), which markets power for periods primarily over
one year, AmerenEnergy Fuels and Services Company, which procures fuel and
manages the related risks for our affiliated companies, and AmerenEnergy
Medina Valley Cogen (No. 4), LLC, which indirectly owns a 40 megawatt,
gas-fired electric generation plant. On February 4, 2003, we completed our
acquisition of AES Medina Valley Cogen (No. 4), LLC and renamed it
AmerenEnergy Medina Valley Cogen (No. 4), LLC. See Note 2 - Acquisitions
for further information.
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 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 Ameren
Corporation and its subsidiaries.
When we refer to Ameren, our, we or us, we are referring to Ameren
Corporation and its subsidiaries on a consolidated basis. In certain
circumstances, our subsidiaries are specifically referenced in order to
distinguish among their different business activities.
The consolidated financial statements include the accounts of Ameren
Corporation and its majority-owned subsidiaries. Results of CILCORP and
AmerenCILCO include the period from the acquisition date of January 31, 2003
through June 30, 2003. See Note 2 - Acquisitions for further information. All
significant intercompany transactions have been eliminated. All tabular dollar
amounts are in millions, unless otherwise indicated.
The accounting policies of Ameren conform to generally accepted accounting
principles in the United States (GAAP). Our financial statements reflect all
adjustments (which include normal, recurring adjustments) necessary, in our
opinion, for a fair presentation of our interim results. These statements should
be read in conjunction with the financial statements and the notes thereto
included in Ameren's, CILCORP's and AmerenCILCO's 2002 Annual Reports on Form
10-K.
6
The preparation of financial statements in conformity with GAAP requires
management to make certain estimates and assumptions. Such estimates and
assumptions affect reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reported period. Actual
results could differ from those estimates. Certain reclassifications have been
made to prior years' financial statements to conform to 2003 reporting.
Earnings Per Share
There was no material difference between the basic and diluted earnings per
share amounts for the three and six month periods ended June 30, 2003 and 2002.
The dilutive component in each of the periods was comprised of assumed stock
option conversions, which increased the number of shares outstanding in the
diluted earnings per share calculation by 306,389 shares for the three months
ended June 30, 2003 (2002 - 355,420) and 273,136 shares for the six months ended
June 30, 2003 (2002 - 353,607).
Accounting Changes and Other Matters
Statement of Financial Accounting Standards (SFAS) No. 143 - "Accounting for
Asset Retirement Obligations"
We adopted the provisions of SFAS 143, effective January 1, 2003. SFAS 143
provides the accounting requirements for asset retirement obligations associated
with tangible, long-lived assets. SFAS 143 requires us to record the estimated
fair value of legal obligations associated with the retirement of tangible
long-lived assets in the period in which the liabilities are incurred and to
capitalize a corresponding amount as part of the book value of the related
long-lived asset. In subsequent periods, we are required to adjust asset
retirement obligations based on changes in estimated fair value. Corresponding
increases in asset book values are depreciated over the remaining useful life of
the related asset. Uncertainties as to the probability, timing or amount of cash
flows associated with an asset retirement obligation affect our estimates of
fair value.
Upon adoption of this standard, we recognized additional asset retirement
obligations of approximately $216 million and a net increase in net property and
plant of approximately $110 million related primarily to the Callaway nuclear
plant decommissioning costs and retirement costs for a river structure and a
power plant ash pond. The difference between the net asset and the liability
recorded upon adoption of SFAS 143 related to rate-regulated assets was recorded
as an additional regulatory asset of approximately $136 million because we
expect to continue to recover in electric rates the cost of Callaway nuclear
decommissioning and other costs of removal. These asset retirement obligations
and associated assets are in addition to assets and liabilities of $174 million
that we had recorded at January 1, 2003, related to our future obligations and
funds accumulated to decommission the Callaway nuclear plant. In addition, we
recognized a net after-tax gain upon adoption of $18 million resulting from a
gain upon elimination of non-legal obligation costs of removal for non
rate-regulated assets from accumulated depreciation ($20 million) and a loss for
the difference between the net asset and liability for retirement obligations to
be recorded upon adoption related to non rate-regulated assets ($2 million).
During the first quarter of fiscal year 2003, our asset retirement
obligations also increased as we assumed CILCORP's asset retirement obligations
of approximately $6 million related to power plant ash ponds in connection with
our acquisition of CILCORP on January 31, 2003.
Asset retirement obligations also increased by $4 million during the
quarter ended March 31, 2003 and $6 million during the quarter ended June 30,
2003 to reflect the obligations at their present value.
In addition to those obligations that were identified and valued, we
determined that certain other asset retirement obligations exist. However, we
are unable to estimate the fair value of those obligations because the
probability, timing or cash flows associated with the obligations are
indeterminable. We do not believe that these obligations, when incurred, will
have a material adverse impact on our financial position, results
7
of operations or liquidity.
The fair value of our nuclear decommissioning trust fund for our Callaway
nuclear plant is reported in Nuclear Decommissioning Trust Fund in our
Consolidated Balance Sheet. This amount is legally restricted for funding the
costs of nuclear decommissioning. Changes in the fair value of the trust fund
are recorded as an increase or decrease to the regulatory asset recorded in
connection with the adoption of SFAS 143.
SFAS 143 required a change in the depreciation methodology we historically
utilized for our non-regulated operations. Historically, we included an
estimated cost of dismantling and removing plant from service upon retirement in
the basis upon which our depreciation rates were determined. SFAS 143 required
us to exclude costs of dismantling and removal upon retirement from the
depreciation rates applied to non rate-regulated plant balances. Further, we
were required to remove accumulated provisions for dismantling and removal costs
from accumulated depreciation, where they were embedded, and reflect such
adjustment as a gain upon adoption of this standard, to the extent such
dismantling and removal activities are not considered legal asset retirement
obligations as defined by SFAS 143. The elimination of cost of removal from
accumulated depreciation resulted in a gain, as noted above, of $20 million, net
of taxes, for a change in accounting principle. Beginning in January 2003,
depreciation rates for non rate-regulated assets were reduced to reflect the
discontinuation of the accrual of dismantling and removal costs. In addition,
non rate-regulated asset removal costs will prospectively be expensed as
incurred. As a result, the impact of this change in accounting will result in a
decrease in depreciation expense and an increase in operations and maintenance
expense, the net impact of which is indeterminable, but not expected to be
material.
Like the methodology employed by our non rate-regulated operations, the
depreciation methodology historically utilized by our rate-regulated operations
has included an estimated cost of dismantling and removing plant from service
upon retirement. Because these estimated costs of removal have been included in
the cost of service upon which our present utility rates are based, and with the
expectation that this practice will continue in the jurisdictions in which we
operate, adoption of SFAS 143 did not result in any change in the depreciation
accounting practices of our rate regulated operations. We have estimated future
removal costs embedded in accumulated depreciation related to rate-regulated
plant assets were approximately $673 million at June 30, 2003.
Emerging Issues Task Force (EITF) Issue No. 02-3 and EITF Issue No. 98-10
In the quarters ended September 30, 2002 and December 31, 2002, we adopted
the provisions of EITF 02-3, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities," that require revenues and costs associated with
certain energy contracts to be shown on a net basis in the income statement.
Prior to adopting EITF 02-3 and the rescission of EITF 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities," our
accounting practice was to present all settled energy purchase or sale contracts
within our power risk management program on a gross basis in Operating Revenues
- - Electric and Other and in Operating Expenses - Fuel and Purchased Power and
Other Operations and Maintenance. This meant that revenues were recorded for the
sum of the contract notional amounts of the power sales contracts with a
corresponding charge to income for the costs of the energy that was generated,
or for the sum of the contract notional amounts of a purchased power contract.
In October 2002, the EITF reached a consensus to rescind EITF 98-10. The
effective date for the full rescission of EITF 98-10 was for fiscal periods
beginning after December 15, 2002, with early adoption permitted. In addition,
the EITF reached a consensus in October 2002 that all SFAS No. 133 ("Accounting
for Derivative Instruments and Hedging Activities") trading derivatives
(subsequent to the rescission of EITF 98-10) should be shown net in the income
statement, whether or not physically settled. This consensus applies to all
energy and non-energy related trading derivatives that meet the definition of a
derivative pursuant to SFAS 133. The operating revenues and costs that were
netted for the three and six months ended June 30, 2002 were $133 million and
$374 million, respectively, which reduced Electric and Other Revenues and
Purchased Power and Other Operations and Maintenance by equal amounts. The
adoption of EITF 02-3, the rescission of EITF 98-10 and the related transition
guidance resulted in netting
8
of energy contracts and lowered our reported revenues and costs with no impact
on earnings.
SFAS No. 148 - "Accounting for Stock-Based Compensation - Transition and
Disclosure"
In December 2002, the Financial Accounting Standards Board (FASB) issued
SFAS 148. SFAS 148 amended SFAS No. 123, "Accounting for Stock-Based
Compensation," to provide alternative methods of transition for an entity that
voluntarily changes to the fair value based method of accounting for stock-based
employee compensation. It also amends the disclosure provisions to require
disclosure about the effects on reported net income of an entity's accounting
policy decisions with respect to stock-based employee compensation. Prior to
2003, we accounted for our stock options granted under our long-term incentive
plan under the recognition and measurement provisions of APB Opinion No. 25,
"Accounting for Stock Issued to Employees." No stock-based employee compensation
cost was reflected for options in 2002, 2001, and 2000 as all options granted
under our plan had an exercise price equal to the market value of the underlying
common stock on the date of grant. The pretax effect of weighted-average
grant-date fair value of options granted would have been approximately $2
million in each of the years ended 2002, 2001, and 2000 had the fair value
method under SFAS 123 been used for options. Effective January 1, 2003, we
adopted the fair value recognition provisions of SFAS 123 by using the
prospective method of adoption under SFAS 148. Because no stock options have
been granted since January 1, 2003, SFAS 148 did not have any effect on our
financial position, results of operations or liquidity in the first six months
of 2003.
SFAS No. 149 - "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities"
In April 2003, the FASB issued SFAS 149. SFAS 149 clarifies under what
circumstances a contract with initial net investment meets the characteristics
of a derivative as discussed in SFAS 133, "Accounting for Derivative Instruments
and Hedging Activities." SFAS 149 is effective for hedging relationships
designated and contracts entered into or modified after June 30, 2003. We do not
expect SFAS 149 to have any impact on our financial position, results of
operations or liquidity upon adoption in the third quarter of 2003.
SFAS No. 150 - "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150 that established standards for how an
issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. SFAS 150 requires financial
instruments that were issued in the form of shares with an unconditional
obligation, where the issuer must redeem the instrument by transferring its
assets on a specified date, be classified as liabilities. Accordingly, SFAS 150
requires issuers to classify mandatorily redeemable financial instruments as
liabilities. SFAS 150 also requires such financial instruments to be measured at
fair value and a cumulative effect adjustment to be recognized in the statement
of income for any difference between the carrying amount and fair value. SFAS
150 will be effective in the third quarter of 2003. AmerenCILCO has $22 million
of preferred stock subject to mandatory redemption. Effective July 1, 2003, this
preferred stock is redeemable at par at any time, and therefore, there is no
difference between book value and fair value.
FASB Interpretation No. (FIN) 46 - "Consolidation of Variable Interest Entities,
an Interpretation of Accounting Research Bulletin (ARB) No. 51, Consolidated
Financial Statements"
The FASB issued FIN 46 in January 2003. FIN 46 provides guidance on the
identification of, and financial reporting for, entities over which control is
achieved through means other than voting rights; such entities are known as
variable-interest entities (VIEs). FIN 46 will determine the following:
o Whether consolidation is required under the "controlling financial
interest" model of ARB 51, or other existing authoritative guidance;
o Or, alternatively, whether the variable-interest model under FIN 46 should
be used to account for existing and new entities.
9
The initial application of FIN 46 depends on the date that the VIE was
created. For public entities, FIN 46 is effective no later than the beginning of
the first interim period that starts after June 15, 2003. At this time, we are
assessing the impact of FIN 46 on our financial position, results of operations,
or liquidity upon adoption in the third quarter of 2003.
Interchange Revenues
Interchange revenues included in Operating Revenues - Electric were $71
million for the three months ended June 30, 2003 (2002 - $67 million) and $185
million for the six months ended June 30, 2003 (2002 - $148 million).
Purchased Power
Purchased power included in Operating Expenses - Fuel and Purchased Power
was $64 million for the three months ended June 30, 2003 (2002 - $52 million)
and $109 million for the six months ended June 30, 2003 (2002 - $104 million).
Excise Taxes
Excise taxes on Missouri electric and gas, and Illinois gas customer bills
are imposed on us and are recorded gross in Operating Revenues and Other Taxes.
Excise taxes recorded in Operating Revenues and Other Taxes for the three months
ended June 30, 2003 were $31 million (2002 - $30 million) and $62 million for
the six months ended June 30, 2003 (2002 - $56 million). Excise taxes applicable
to Illinois electric customer bills are imposed on the consumer and are recorded
as tax collections payable and included in Taxes Accrued on the Consolidated
Balance Sheet.
Goodwill
Goodwill is the excess of the purchase price of an acquisition over the
fair value of the net assets acquired. We do not amortize goodwill under the
provisions of SFAS 142, "Goodwill and Other Intangible Assets." SFAS 142
requires the evaluation of goodwill for impairment at least annually or more
frequently if events and circumstances indicate that the asset might be
impaired.
Pension
At December 31, 2002, we recorded a minimum pension liability of $102
million, after taxes, which resulted in a charge to Accumulated Other
Comprehensive Income (Loss)(OCI) and a reduction in stockholders' equity. Based
on changes in interest rates, we may need to change our actuarial assumptions
for our pension plan at December 31, 2003, which could result in a requirement
to record an additional minimum pension liability.
NOTE 2 - Acquisitions
On January 31, 2003, we completed our acquisition of all of the outstanding
common stock of CILCORP from The AES Corporation. CILCORP is the parent company
of Peoria, Illinois-based Central Illinois Light Company, which operated as
CILCO. With the acquisition, CILCO became an indirect Ameren subsidiary, but
remains a separate utility company, operating as AmerenCILCO. On February 4,
2003, we also completed our acquisition of AES Medina Valley Cogen (No. 4), LLC
(Medina Valley), which indirectly owns a 40 megawatt, gas-fired electric
generation plant. With the acquisition, Medina Valley, which we renamed as
AmerenEnergy Medina Valley Cogen (No. 4), LLC, became a wholly-owned subsidiary
of Resources Company. The results of operations for CILCORP and AmerenEnergy
Medina Valley Cogen (No. 4), LLC were included in our consolidated financial
statements effective with the January and February 2003 acquisition dates.
10
We acquired CILCORP to complement our existing Illinois gas and electric
operations. The purchase included CILCO's rate-regulated electric and natural
gas businesses in Illinois serving approximately 200,000 and 205,000 customers,
respectively, of which approximately 150,000 are combination electric and gas
customers. CILCO's service territory is contiguous to our service territory.
CILCO also has a non rate-regulated electric and gas marketing business
principally focused in the Chicago, Illinois region. Finally, the purchase
included approximately 1,200 megawatts of largely coal-fired generating
capacity, most of which is expected to become non rate-regulated in 2003.
The total acquisition cost was approximately $1.4 billion and included the
assumption of CILCORP and Medina Valley debt and preferred stock at closing of
$895 million and consideration of $489 million in cash, net of cash acquired.
The cash component of the purchase price came from Ameren's issuance in
September 2002 of 8.05 million common shares and its issuance in early 2003 of
an additional 6.325 million common shares which together generated aggregate net
proceeds of $575 million.
The following unaudited pro forma financial information presents a summary
of our combined results of operations assuming the acquisitions of CILCORP and
Medina Valley had been completed at the beginning of fiscal year 2002, including
pro forma adjustments, which are based upon preliminary estimates, to reflect
the allocation of the purchase price to the acquired net assets. We are in the
process of completing a third party valuation of acquired property and plant and
intangible assets. Therefore, the allocation of the purchase price is subject to
refinement. The excess of the purchase price over tangible net assets acquired
has been allocated preliminarily to goodwill in the amount of $604 million.
- -----------------------------------------------------------------------------------------------------------------
For the periods ended June 30, Pro Forma Three Months Pro Forma Six Months
- -----------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------
Operating revenues $ 1,088 $ 1,146 $ 2,296 $ 2,217
Income before cumulative effect of
change in accounting principle 110 117 197 181
Cumulative effect of change in accounting
principle, net of taxes - - 22 -
- -----------------------------------------------------------------------------------------------------------------
Net income $ 110 $ 117 $ 219 $ 181
Earnings per share -basic $ 0.68 $ 0.74 $ 1.36 $ 1.16
-diluted $ 0.68 $ 0.74 $ 1.36 $ 1.16
- -----------------------------------------------------------------------------------------------------------------
This pro forma information is not necessarily indicative of the results of
operations as they would have been had the transactions been effected on the
assumed date, nor is it an indication of trends in future results.
NOTE 3 - Rate and Regulatory Matters
Intercompany Transfer of Electric Generating Facilities and Illinois Service
Territory
As a part of the settlement of the Missouri electric rate case in 2002,
AmerenUE committed to making certain infrastructure investments from January 1,
2002 through June 30, 2006. The requirements are expected to be satisfied in
part by the proposed transfer from Generating Company to AmerenUE, at net book
value, of approximately 550 megawatts of combustion turbine generating units at
Pinckneyville and Kinmundy, Illinois. The transfer is subject to receipt of
necessary regulatory approvals. Approval by the Missouri Public Service
Commission (MoPSC) is not required in order for this transfer to occur. However,
the MoPSC has jurisdiction over AmerenUE's ability to recover the cost of the
transferred generating facilities from its electric customers in its rates. As a
part of the settlement of the Missouri electric rate
11
case in 2002, AmerenUE is subject to a rate moratorium providing for no changes
in electric rates before June 30, 2006, subject to certain statutory and other
exceptions.
In February 2003, we sought approval from the Federal Energy Regulatory
Commission (FERC) and the Illinois Commerce Commission (ICC) to transfer the 550
megawatts of generating assets from Generating Company to AmerenUE. Several
independent power producers have objected to Ameren's request to the FERC based
on a claim that the transfer may harm competition for the sale of electricity at
wholesale. In April 2003, NRG Energy Inc. (NRG) and some of its affiliates filed
testimony in the ICC proceeding contending that NRG's 640 megawatt generating
facility at Vandalia, Missouri, known as the Audrain Facility, was a better
resource for AmerenUE to acquire as compared to the Kinmundy and Pinckneyville
combustion turbine generating units. In addition, the ICC Staff filed testimony
that expressed concerns about whether the transfer is the least cost generating
resource for AmerenUE, and recommended that the ICC deny approval of the
transfer.
On May 5, 2003, the FERC issued an order which set for hearing the effect
ofthe proposed transfer on competition in wholesale electric markets. On June4,
2003, we filed a Motion for Reconsideration of this order contending that the
FERC erred in setting this matter for hearing. On June 10, 2003, we filed direct
testimony with the FERC in support of the proposed transfer. On August 8, 2003,
two intervenors, NRG and The Electric Power Supply Association, filed testimony
opposing the proposed transfer.
On May 30, 2003, AmerenUE filed a Notice of Withdrawal with the ICC stating
that AmerenUE elected not to pursue approval of the transfer and was withdrawing
its request. In the Notice, AmerenUE stated that the concerns expressed by the
ICC Staff regarding AmerenUE's means of satisfying its generating capacity
needs, as well as the MoPSC's views of the appropriate means of meeting
generating capacity obligations, have demonstrated to AmerenUE the difficulty of
a single company operating as an electric utility in both a regulated generation
jurisdiction such as Missouri and an unregulated generation jurisdiction such as
Illinois. To remedy this difficulty, AmerenUE announced in the Notice its plan
to limit its public utility operations to the State of Missouri and to
discontinue operating as a public utility subject to ICC regulation. AmerenUE
intends to accomplish this plan by transferring its Illinois-based electric and
natural gas businesses, including its Illinois-based distribution assets and
certain of its transmission assets, to AmerenCIPS. AmerenUE's electric
generating facilities and certain of its electric transmission facilities in
Illinois would not be part of the transfer. The transfer of AmerenUE's
Illinois-based utility businesses will require the approval of the ICC, the
FERC, the MoPSC and the SEC under the provisions of the PUHCA. On June 13, 2003,
the ICC Staff filed a response to AmerenUE's Notice of Withdrawal indicating
that the ICC Staff did not object to it and on July 23, 2003, the ICC issued an
order accepting the withdrawal. In the third quarter of 2003, we expect to file
with the MoPSC, the ICC, the FERC and the SEC for authority to transfer
AmerenUE's Illinois-based utility businesses, at net book value, to AmerenCIPS.
Upon receipt of regulatory approvals and completion of the transfer of its
Illinois-based utility businesses, the ICC's approval will no longer be required
for the Pinckneyville and Kinmundy combustion turbine generating units to be
transferred from Generating Company to AmerenUE. We intend to continue with the
transfer of these electric generating facilities and will continue to seek
approvals from regulators having jurisdiction over the transaction. FERC
approval of the transaction is needed, and because the transaction does not
require state regulatory approvals, SEC approval under the PUHCA is also
required.
We are unable to predict the ultimate outcome of these regulatory
proceedings or the timing of the final decisions of the various agencies. The
timing of regulatory approvals of these proposed transactions is not anticipated
to have any material effect on our financial position, results of operations or
liquidity.
Regional Transmission Organization (RTO)
Since April 2002, AmerenCIPS and AmerenUE and subsidiaries of FirstEnergy
Corporation and NiSource Inc. (collectively the GridAmerica Companies) have
participated in a number of filings at the FERC in an effort to form GridAmerica
LLC as an independent transmission company (ITC). On December 19, 2002, the FERC
issued an order conditionally approving the formation and operation of
12
GridAmerica as an ITC within the Midwest Independent System Operator (Midwest
ISO), subject to further compliance filings.
In response to the December 19, 2002 order, the GridAmerica Companies made
three additional filings at the FERC. On January 31, 2003, the GridAmerica
Companies filed a request for authorization to transfer functional control of
certain transmission assets to GridAmerica. On February 18, 2003, the
GridAmerica Companies filed revised agreements codifying the formation and
operation of GridAmerica to reflect changes requested by the FERC in the
December 19, 2002 order. On February 28, 2003, the GridAmerica Companies
together with the Midwest ISO filed revisions to the Midwest ISO Open Access
Transmission Tariff (OATT) to provide rates for service over the transmission
facilities to be transferred to GridAmerica by the GridAmerica Companies.
On April 30, 2003, the FERC issued orders in response to the January 31,
2003 and February 28, 2003 filings. In its order regarding the GridAmerica
Companies' request to transfer functional control of their transmission assets
to GridAmerica, the FERC authorized the transfer. In response to the February
28, 2003 filing, the FERC accepted the amendments to the Midwest ISO OATT
effective upon the commencement of service over the GridAmerica transmission
facilities under the Midwest ISO OATT, suspended the proposed rates for a
nominal period, subject to refund, and established hearing and settlement
procedures to determine the justness and reasonableness of the proposed rate
amendments to the Midwest ISO OATT. At this time, the parties are pursuing
settlement of the disputed rate issues. Absent settlement, the rates filed in
the February 28, 2003 filing will go into effect on October 1, 2003, subject to
refund. On May 15, 2003, the FERC issued an order accepting the February 18,
2003 compliance filing.
Once GridAmerica becomes operational and Ameren has secured approval to
participate in GridAmerica from the MoPSC, the FERC has ordered the return of
the $18 million exit fee, with interest, paid by Ameren when it previously left
the Midwest ISO. Until the tariffs and other material terms of AmerenCIPS' and
AmerenUE's participation in GridAmerica, and GridAmerica's participation in the
Midwest ISO, are finalized and approved by the FERC, we are unable to predict
the impact that on-going regional transmission organization developments will
have on our financial position, results of operations or liquidity. AmerenUE's
participation in GridAmerica is subject to MoPSC approval. We expect GridAmerica
to become operational in late 2003, subject to regulatory approvals.
In July 2003, the FERC issued an Order (July Order) that could potentially
reduce Ameren's, as well as other utilities', "through and out" transmission
revenues effective November 1, 2003, reversing an Administrative Law Judge's
previous decision on this matter. The revenues subject to elimination by the
July Order are those revenues from transmission reservations that travel through
or out of our transmission system and are also used to provide electricity to
load within the Midwest ISO or PJM Interconnection LLC systems. The magnitude
of the potential net revenue reduction resulting from the July Order is still
being evaluated, but could be up to $20 to $25 million annually. While it is
anticipated that our transmission revenues could be reduced by the July Order,
transmission expenses for our affiliates could also be reduced. Moreover, the
FERC's Order explicitly permits companies participating in an RTO to seek
collection of the lost "through and out" revenues through other rate
mechanisms. At this time, we intend to seek rehearing of the July Order. We
also intend to seek recovery of any potential lost "through and out" revenues
through rate mechanisms acknowledged by the FERC in the July Order.
Standard Market Design Notice of Proposed Rulemaking (NOPR)
On July 31, 2002, the FERC issued a Standard Market Design NOPR. The NOPR
proposes a number of changes to the way the current wholesale transmission
service and energy markets are operated. Specifically, the NOPR calls for all
jurisdictional transmission facilities to be placed under the control of an
independent transmission provider (similar to an RTO), proposes a new
transmission service tariff that provides a single form of transmission service
for all users of the transmission system including bundled retail load, and
proposes a new energy market and congestion management system that uses
locational marginal pricing as its basis.
13
Although issuance of the final rule is uncertain and the implementation
schedule is unknown, the Midwest ISO is already in the process of implementing a
separate market design similar to the proposed market design in the NOPR. In
July 2003, the Midwest ISO filed with the FERC a revised OATT codifying the
terms and conditions under which it will implement the new market design. The
Midwest ISO has targeted March 2004 as the start date for implementation. We are
reviewing the Midwest ISO's market design and the potential impact of the market
design on the cost and reliability of service to retail customers. At this time,
we are unable to predict the ultimate impact the new market design will have on
our future financial position, results of operations or liquidity.
Illinois Gas
In November 2002, AmerenCIPS, AmerenUE and CILCO (now AmerenCILCO) filed
requests with the ICC to increase annual rates for natural gas service by
approximately $16 million, $4 million and $14 million, respectively. The ICC
Staff has recommended annual increases of approximately $8 million, $2 million
and $9 million, respectively. In addition, other parties have proposed lower
increases in each case. Hearings were completed in June and July 2003. In August
2003, the Administrative Law Judge in the CILCO gas rate proceeding recommended
to the ICC the adoption of a Proposed Order to increase annual rates for natural
gas service by $10 million at CILCO. The ICC has until October 2003 to render a
decision in each of these gas cases and any rate changes are expected to be
effective in November 2003.
Missouri Gas
In May 2003, AmerenUE filed a request with the MoPSC to increase annual
rates for natural gas service by approximately $27 million. AmerenUE proposed to
phase in the rate increases over two years, with one half of the increase taking
effect December 1, 2003 and the other half taking effect November 1, 2004. We
also proposed not to seek additional increases in gas rates through November 1,
2006, subject to certain exceptions. Our proposal also called for us to
contribute $1.75 million to an energy assistance program to help low-income
customers. The direct testimony of the MoPSC Staff and other parties to this
proceeding is due to be filed with the MoPSC in October 2003. A pre-hearing
settlement conference is scheduled to be held in October 2003 and a hearing is
scheduled to be held in January 2004. The MoPSC has until April 2004 to render a
decision in this gas case.
NOTE 4 - Derivative Financial Instruments
As of June 30, 2003, we recorded the fair value of derivative financial
instrument assets of $10 million in Other Assets and the fair value of
derivative financial instrument liabilities of $9 million in Other Deferred
Credits and Liabilities.
Cash Flow Hedges
The pretax net gain or loss on power forward derivative instruments, which
represented the impact of discontinued cash flow hedges, the ineffective portion
of cash flow hedges, as well as the reversal of amounts previously recorded in
OCI due to transactions going to delivery or settlement, was less than a $1
million gain for the three months (2002 - less than a $1 million loss) and a $1
million loss for the six months ended June 30, 2003 (2002 - less than a $1
million gain).
As of June 30, 2003, we hedged a portion of the electricity price exposure
for periods generally less than one year. Certain contracts that are designated
as hedges of electricity price exposure have terms up to five years. The
mark-to-market value accumulated in OCI for the effective portion of hedges of
electricity price exposure was a net loss of approximately $1 million (less than
$1 million, net of taxes).
As of June 30, 2003, a gain of approximately $6 million ($4 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 cover the first ten years of debt that has a 30-year maturity and the gain
in OCI is amortized over a ten-year period that began in June 2002.
14
As of June 30, 2003, a loss of approximately $4 million ($2 million, net of
taxes), associated with natural gas swaps and future contracts, was included in
OCI. The swaps are a partial hedge of our natural gas requirements through
October 2006.
We also hold two call options for coal with two suppliers. These options to
purchase coal expire October 2003 and July 2005. As of June 30, 2003, a
mark-to-market gain of approximately $5 million ($3 million, net of taxes)
associated with these options was included in OCI. The final value of the
options will be recognized as a reduction in fuel costs as the hedged coal is
burned.
Other Derivatives
We enter into option transactions to manage our positions in sulfur dioxide
allowances, coal, heating oil and electricity. Certain of these transactions are
treated as non-hedge transactions under SFAS 133. The net change in the market
value of sulfur dioxide options is recorded as Operating Revenues - Electric,
while the net change in the market value of coal, heating oil and electricity
options is recorded as Operating Expenses - 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 less than $1 million (less
than $1 million, net of taxes) for the three months ended June 30, 2003 and a
gain of $1 million (less than $1 million, net of taxes) for the six months ended
June 30, 2003. For the three and six months ended June 30, 2002, the above
related amounts were a $2 million gain ($1 million, net of taxes) and a $3
million gain ($2 million, net of taxes).
NOTE 5 - Property and Plant, Net
Property and plant, net at June 30, 2003 and December 31, 2002 consisted of
the following:
- ---------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------
June 30, December 31,
2003 2002
- ---------------------------------------------------------------------------------------------
Property and plant, at original cost:
Electric $15,895 $14,495
Gas 725 557
Other 196 145
- ---------------------------------------------------------------------------------------------
16,816 15,197
Less accumulated depreciation and amortization 7,075 6,831
- ---------------------------------------------------------------------------------------------
9,741 8,366
Construction work in progress:
Nuclear fuel in process 71 81
Other 385 393
- --------------------------------------------------------------------------------------------
Property and plant, net $10,197 $8,840
- --------------------------------------------------------------------------------------------
NOTE 6 - Debt and Equity Financings
Ameren Corporation
In August 2002, the SEC declared effective a shelf registration statement
filed by Ameren Corporation covering the offering from time to time of up to
$1.473 billion of various forms of securities including long-term debt, and
trust preferred and equity securities to finance ongoing construction and
maintenance programs, to redeem, repurchase, repay, or retire outstanding debt,
and to finance strategic investments, including our then pending acquisition of
CILCORP, and for general corporate purposes.
In the first quarter of 2003, Ameren Corporation issued, pursuant to the
shelf registration statement, 6.325 million shares of its common stock at $40.50
per share. We received net proceeds after fees of $248 million, which were used
to fund the remaining cash portion of the purchase price for our acquisition of
15
CILCORP. See Note 2 - Acquisitions for further information. We may sell all, or
a portion of, the remaining securities registered 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 2002 and in the first six months of 2003, $594 million was issued
under this shelf registration statement. At June 30, 2003, the amount of
securities remaining to be issued pursuant to the registration statement was
$879 million.
The purchases of CILCORP on January 31, 2003 and Medina Valley on February
4, 2003 included the assumption of CILCORP and Medina Valley debt and preferred
stock at closing of $895 million. The assumed debt primarily consisted of $250
million 9.375% senior notes due 2029, $225 million 8.7% senior notes due 2009, a
$100 million secured floating rate term loan due 2004, other secured
indebtedness totaling $279 million and preferred stock of $41 million.
Subsequent to the acquisition dates, the other secured indebtedness was reduced
by $136 million through maturities and early redemptions.
In July 2003, Ameren Corporation entered into two new credit agreements for
$470 million in revolving credit facilities to be used for general corporate
purposes, including support of our commercial paper programs. The $470 million
in new facilities includes a $235 million 364-day revolving credit facility and
a $235 million three-year revolving credit facility. These new credit facilities
replaced Ameren Corporation's existing $270 million 364-day revolving credit
facility, which matured in July 2003 and a $200 million facility, which would
have matured in December 2003. The new credit facilities contain provisions
which require us to meet minimum Employee Retirement Income Security Act (ERISA)
funding requirements for our pension plan. The prior credit facilities included
more restrictive provisions related to the funded status of our pension plan,
which are not present in the new facilities. In addition, in July 2003, Ameren
Corporation entered into an amendment of an existing $130 million multi-year
credit facility that similarly modified the ERISA-related provisions in this
facility. As a result, all of Ameren Corporation's facilities require us to meet
minimum ERISA funding requirements, but do not otherwise limit the underfunded
status of our pension plan. At July 31, 2003, all of such borrowing capacity
under these facilities was available.
At June 30, 2003, neither Ameren Corporation, nor any of its subsidiaries,
had any off-balance sheet financing arrangements, other than operating leases
entered into in the ordinary course of business.
Amortization of debt issuance costs and any premium or discounts for the
three and six months ended June 30, 2003 of $3 million (2002 - $2 million) and
$5 million (2002 - $4 million), respectively, were included in interest expense
in the income statement. Amortization related to recording the fair value of
debt assumed upon the acquisition of CILCORP was approximately $2 million for
the three months and $3 million for the five months ended June 30, 2003. The
amortization was included in interest expense in the income statement.
At June 30, 2003, Ameren Corporation and its subsidiaries were in
compliance with their financial agreement provisions and covenants.
AmerenUE
In August 2002, the SEC declared effective a shelf registration statement
filed by AmerenUE covering the offering from time to time of up to $750 million
of various forms of long-term debt and trust preferred securities to refinance
existing debt and preferred stock, and for general corporate purposes, including
the repayment of short-term debt incurred to finance construction expenditures
and other working capital needs.
In March 2003, AmerenUE issued, pursuant to the shelf registration
statement, $184 million of 5.50% Senior Secured Notes due March 15, 2034.
AmerenUE received net proceeds after fees of $180 million, which, along with
other funds, were used to redeem $104 million principal amount of outstanding
8.25% first mortgage bonds due October 15, 2022, at a redemption price of
103.61% of par, plus accrued interest, in April 2003, prior to maturity, and to
repay short-term debt incurred to pay at maturity $75 million principal amount
of 8.33% first mortgage bonds that matured in December 2002.
16
In April 2003, AmerenUE issued, pursuant to the shelf registration
statement, $114 million of 4.75% Senior Secured Notes due April 1, 2015.
AmerenUE received net proceeds after fees of $113 million, which, along with
other funds, were used to redeem $85 million principal amount of outstanding
8.00% first mortgage bonds due December 15, 2022, at a redemption price of
103.38% of par, plus accrued interest, prior to maturity, and to reduce
short-term debt.
In July 2003, AmerenUE issued $200 million of 5.10% Senior Secured Notes
due August 1, 2018. AmerenUE received net proceeds after fees of $198 million,
which, along with other funds were used to repay short-term debt incurred to
fund the maturity of $100 million principal amount 7.65% first mortgage bonds
due July 15, 2003, and to repay $21 million of other short-term debt. The
remaining proceeds will be used to redeem and refinance, prior to maturity, $75
million principal amount of outstanding 7.15% first mortgage bonds due August 1,
2023 at a redemption price of 103.01% of par, plus accrued interest in August
2003.
In August 2003, AmerenUE plans to file another shelf registration statement
with the SEC. We expect this registration statement, when declared effective by
the SEC, will authorize the offering from time to time of up to $1 billion of
various forms of long-term debt and trust preferred securities to refinance
existing debt and for general corporate purposes, including the repayment of
short-term debt incurred to finance construction expenditures and other working
capital needs. The $79 million of securities which remains to be issued under
the August 2002 shelf registration is expected to be included in the $1 billion
of securities proposed to be issued under this registration statement.
Once declared effective by the SEC, AmerenUE may sell all, or a portion of,
the securities registered under the AmerenUE shelf registration statement if
warranted by market conditions and our capital requirements. Any offer and sale
will be made only by means of a prospectus meeting the requirements of the
Securities Act of 1933 and the rules and regulations thereunder.
In April 2003, AmerenUE entered into an additional 364-day committed credit
facility totaling $75 million to be used for general corporate purposes,
including support of commercial paper programs. This facility makes borrowings
available at various interest rates based on LIBOR, agreed rates and other
options. AmerenCIPS can access this facility through the utility money pool.
AmerenCIPS
On April 1, 2003, AmerenCIPS repaid $40 million first mortgage bonds 6.375%
Series Z which matured on that date. AmerenCIPS also redeemed, in April 2003,
prior to maturity and at par, its $50 million first mortgage bonds 7.5% Series X
due July 1, 2007.
AmerenCILCO
In April 2003, three series of AmerenCILCO's first mortgage bonds were
redeemed prior to maturity. These included AmerenCILCO's $65 million principal
amount 8.20% series notes due January 15, 2022, at a redemption price of 103.29%
and two 7.8% series notes totaling $10 million principal amount due February 9,
2023, at a redemption price of 103.90%.
Other
On June 30, 2003, AmerenEnergy Medina Valley Cogen, LLC repaid, prior to
maturity, a $36 million secured term loan with an effective interest rate of
7.65% and terminated two related interest rate swaps. This redemption eliminated
the outstanding bank debt at AmerenEnergy Medina Valley Cogen, LLC.
17
NOTE 7 - Miscellaneous, Net
Miscellaneous, net for the three and six months ended June 30, 2003 and
2002 consisted of the following:
- --------------------------------------------------------------------------------
Three Months Six Months
- --------------------------------------------------------------------------------
2003 2002 2003 2002
---- ---- ---- ----
Miscellaneous income:
Interest and dividend income $ 1 $ 2 $ 2 $ 2
Gain on disposition of property - 3 - 3
Other 4 - 9 3
- --------------------------------------------------------------------------------
Total miscellaneous income $ 5 $ 5 $ 11 $ 8
- --------------------------------------------------------------------------------
Miscellaneous expense:
Minority interest in subsidiary $ (4) $(10) $ (5) $(11)
Donations, including 2002 rate settlement (1) (26) (1) (26)
Other (3) (3) (5) (6)
- --------------------------------------------------------------------------------
Total miscellaneous expense $ (8) $(39) $(11) $(43)
- --------------------------------------------------------------------------------
NOTE 8 - Segment Information
Ameren's principal business segment is comprised of the utility operating
companies that provide electric and gas service in portions of Missouri and
Illinois. The other reportable segment includes our nonutility subsidiaries, as
well as our 60% interest in EEI.
The accounting policies of the segments are the same as those described in
Note 1 - Summary of Significant Accounting Policies. Segment data includes
intersegment revenues, as well as a charge for allocating costs of
administrative support services to each of the operating companies. These costs
are accumulated in a separate subsidiary, Ameren Services Company, which
provides a variety of support services to Ameren and its subsidiaries.
Segment information for the three and six months ended June 30, 2003 and
2002 was as follows:
- ------------------------------------------------------------------------------------------------------------------
Utility Intercompany
Operations Other Revenues Total
- ------------------------------------------------------------------------------------------------------------------
Three months ended June 30, 2003:
Revenues $1,189 $ 75 $(176) $1,088
Net income 108 2 - 110
- ------------------------------------------------------------------------------------------------------------------
Three months ended June 30, 2002:
Revenues $1,046 $106 $(174) $ 978
Net income 101 14 - 115
- ---------------------------------------------------------------------------------------------------------------
Six months ended June 30, 2003:
Revenues $2,436 $ 122 $(362) $2,196
Net income 210 1 - 211
- -------------------------------------------------------------------------------------------------------------
Six months ended June 30, 2002:
Revenues $2,041 $ 175 $(364) $1,852
Net income 159 15 - 174
- ------------------------------------------------------------------------------------------------------------
18
Ameren Services Company allocates administrative support services to each
segment based on various factors, such as headcount, number of customers, and
total assets.
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
OVERVIEW
Ameren Corporation is a public utility holding company registered with the
Securities and Exchange Commission (SEC) under the Public Utility Holding
Company Act of 1935 (PUHCA) and is headquartered in St. Louis, Missouri. 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 rate-regulated electric
generation, transmission and distribution business, and a rate-regulated
natural gas distribution business in Missouri and Illinois as AmerenUE.
o Central Illinois Public Service Company, which operates a rate-regulated
electric and natural gas transmission and distribution business in Illinois
as AmerenCIPS.
o Central Illinois Light Company, a subsidiary of CILCORP Inc. (CILCORP),
which operates a rate-regulated electric transmission and distribution
business, an electric generation business, and a rate-regulated natural gas
distribution business in Illinois as AmerenCILCO. We completed our
acquisition of CILCORP on January 31, 2003. See Acquisitions for further
information.
o AmerenEnergy Resources Company (Resources Company), which consists of non
rate-regulated operations. Subsidiaries include AmerenEnergy Generating
Company (Generating Company), which operates non rate-regulated electric
generation in Missouri and Illinois, AmerenEnergy Marketing Company
(Marketing Company), which markets power for periods primarily over one
year, AmerenEnergy Fuels and Services Company, which procures fuel and
manages the related risks for our affiliated companies, and AmerenEnergy
Medina Valley Cogen (No. 4), LLC, which indirectly owns a 40 megawatt,
gas-fired electric generation plant. On February 4, 2003, we completed our
acquisition of AES Medina Valley Cogen (No. 4), LLC and renamed it
AmerenEnergy Medina Valley Cogen (No. 4), LLC. See Acquisitions for further
information.
o AmerenEnergy, Inc. (AmerenEnergy), which serves as a power marketing and
risk management agent for our affiliated companies for transactions of
primarily less than one year.
o Electric Energy, Inc. (EEI), which operates electric generation and
transmission facilities in Illinois. We have a 60% ownership interest in
EEI and consolidate it for financial reporting purposes.
o Ameren Services Company, which provides shared support services to Ameren
Corporation and its 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 financial statements and related notes included in our Quarterly Report
on Form 10-Q for the period ended March 31, 2003.
o Management's Discussion and Analysis of Financial Condition and Results of
Operations that is incorporated by reference from our 2002 Annual Report to
Shareholders into our Annual Report on Form 10-K for the period ended
December 31, 2002, as amended by Form 10-K/A.
o The audited financial statements and related notes that are incorporated by
reference from our 2002 Annual Report to Shareholders into our Annual
Report on Form 10-K for the period ended December 31, 2002, as amended by
Form 10-K/A.
o Management's Discussion and Analysis of Financial Condition and Results of
Operations in CILCORP and AmerenCILCO's Annual Report on Form 10-K for the
period ended December 31, 2002.
o The audited financial statements and related notes in CILCORP and
AmerenCILCO's Annual Report on Form 10-K for the period ended December 31,
2002.
19
When we refer to Ameren, our, we or us, we are referring to Ameren
Corporation and its subsidiaries 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. Results of CILCORP and
AmerenCILCO include the period from the acquisition date of January 31, 2003
through June 30, 2003.
Our results of operations and financial position are affected by many
factors. Weather, economic conditions and the actions of key customers or
competitors can significantly impact the demand for our services. Our results
are also affected by seasonal fluctuations caused by winter heating, and summer
cooling, demand. With 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, natural gas and oil 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 cost recovery mechanisms in Missouri or Illinois for our electric
utility businesses, but we do have gas cost recovery mechanisms in each state
for our gas utility businesses. In addition, our electric rates in Missouri and
Illinois are largely set through 2006. Fluctuations in interest rates impact our
cost of borrowings, and pension and post-retirement benefits. We employ various
risk management strategies in order to try to reduce our exposure to commodity
risks and other risks inherent in our business. The reliability of our power
plants, and transmission and distribution systems, and the level of operating
and administrative costs, and capital investment are key factors that we seek to
control in order to optimize our results of operations, cash flows and financial
position.
Acquisitions
On January 31, 2003, we completed our acquisition of all of the outstanding
common stock of CILCORP from The AES Corporation. CILCORP is the parent company
of Peoria, Illinois-based Central Illinois Light Company, which operated as
CILCO. With the acquisition, CILCO became an indirect Ameren subsidiary, but
remains a separate utility company, operating as AmerenCILCO. On February 4,
2003, we also completed our acquisition of AES Medina Valley Cogen (No. 4), LLC
(Medina Valley), which indirectly owns a 40 megawatt, gas-fired electric
generation plant. With the acquisition, Medina Valley, which we renamed
AmerenEnergy Medina Valley Cogen (No. 4), LLC, became a wholly-owned subsidiary
of Resources Company. The results of operations for CILCORP and AmerenEnergy
Medina Valley Cogen (No. 4), LLC were included in our consolidated financial
statements effective with the January and February 2003 acquisition dates.
We acquired CILCORP to complement our existing Illinois gas and electric
operations. The purchase included CILCO's rate-regulated electric and natural
gas businesses in Illinois serving approximately 200,000 and 205,000 customers,
respectively, of which approximately 150,000 are combination electric and gas
customers. CILCO's service territory is contiguous to our service territory.
CILCO also has a non rate-regulated electric and gas marketing business
principally focused in the Chicago, Illinois region. Finally, the purchase
included approximately 1,200 megawatts of largely coal-fired generating
capacity, most of which is expected to become non rate-regulated in 2003.
The total acquisition cost was approximately $1.4 billion and included the
assumption of CILCORP and Medina Valley debt and preferred stock at closing of
$895 million and consideration of $489 million in cash, net of cash acquired.
The cash component of the purchase price came from Ameren's issuances in
September 2002 of 8.05 million common shares and its issuance in early 2003 of
an additional 6.325 million common shares which together generated aggregate net
proceeds of $575 million.
20
RESULTS OF OPERATIONS
Earnings Summary
Our net income decreased $5 million to $110 million, or 68 cents per share,
in the second quarter of 2003 from $115 million, or 80 cents per share, in the
second quarter of 2002. Net income decreased in the second quarter of 2003 as
compared to 2002 principally as a result of milder weather, lower sales of
emission credits, increased dilution and financing costs outside of those
incurred in connection with the CILCORP acquisition and higher depreciation
expense. Partially offsetting these items were lower operations and maintenance
expenses, excluding CILCORP, and favorable interchange margins due to improved
power prices in the energy markets and solid low-cost generation available for
sale. In addition, we expensed costs of economic development and energy
assistance programs that were required by a Missouri electric rate case
settlement in the second quarter of 2002.
Our net income increased $37 million to $211 million, or $1.32 per share
($1.32 per share diluted), for the six months ended June 30, 2003 compared to
the year-ago earnings of $174 million, or $1.22 per share. In the first six
months of 2003, our net income included a net cumulative effect gain of $18
million, or 11 cents per share, associated with the adoption of Statement of
Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement
Obligations." The net gain resulted principally from the elimination of
non-legal obligation costs of removal for non rate-regulated assets from
accumulated depreciation. In addition to the items discussed above, net income
for the first six months of 2003 benefited from higher interchange margins as
well as colder winter weather than 2002, which resulted in increased native load
electric demand and higher gas margins in the first quarter of 2003.
The impact from the acquisition of CILCORP and related financings resulted
in a reduction to earnings per share in the second quarter and the first six
months of 2003 of approximately 3 cents and 5 cents per share, respectively. We
continue to believe the operations of CILCORP will be accretive to earnings in
the first full year following the acquisition date as we realize the synergies
associated with this acquisition following the integration of systems and
operating practices later in 2003.
Because we are a holding company, our net income and cash flows are
primarily generated by our principal operating subsidiaries, AmerenUE,
AmerenCILCO, AmerenCIPS and Generating Company. These subsidiaries also file
quarterly and annual reports with the SEC. The contribution by our principal
operating subsidiaries to net income for the three and six months ended June 30,
2003 and 2002 was as follows:
-------------------------------------------------------------------------------------------
Three Months Six Months
- -------------------------------------------------------------------------------------------
2003 2002 2003 2002
---- ---- ---- -----
Primarily rate-regulated operations
AmerenUE (a) $ 105 $ 105 $ 172 $ 154
CILCORP (b) - - 3 -
AmerenCIPS 3 7 4 8
- -------------------------------------------------------------------------------------------
$ 108 $ 112 $ 179 $ 162
- -------------------------------------------------------------------------------------------
Primarily non rate-regulated operations
Generating Company (a)(c) 10 3 49 16
Other (d) (8) - (17) (4)
- ------------------------------------------------------------------------------------------
Ameren net income $ 110 $ 115 $ 211 $ 174
- ------------------------------------------------------------------------------------------
(a) Includes earnings from interchange sales by AmerenEnergy that provided
approximately $11 million and $33 million of AmerenUE's net income in the
three and six months ended June 30, 2003 (2002 - second quarter - $4
million; year-to-date - $9 million). Includes earnings from interchange
sales by AmerenEnergy that provided approximately $5 million and $17
million of Generating Company's net income in the three and six months
ended June 30, 2003 (2002 - second quarter - $2 million; year-to-date - $5
million).
(b) Most of CILCORP's electric generation business is expected to become non
rate-regulated in 2003 with the transfer of substantially all of its
generating assets to a non rate-regulated subsidiary.
21
(c) Includes earnings from contracts to supply power to our rate-regulated
AmerenCIPS customers.
(d) Includes corporate general and administrative expenses, transition costs
associated with the CILCORP acquisition, stock compensation and other
unregulated operations.
Electric Operations
The following table represents the favorable (unfavorable) variations on
electric margin for the three and six months ended June 30, 2003 from the
comparable period in 2002:
- --------------------------------------------------------------------------------
Three Months Six Months
- --------------------------------------------------------------------------------
Electric Revenues:
CILCORP $ 124 $ 204
Interchange revenues 5 41
Effect of weather (estimate) (60) (32)
Rate reductions (5) (16)
Growth and other (estimate) 10 (2)
EEI (36) (48)
- --------------------------------------------------------------------------------
Total variation in electric operating revenues 38 147
- --------------------------------------------------------------------------------
Fuel and Purchased Power:
Fuel:
Generation $ (2) (15)
Price 11 10
Generation efficiencies and other (2) (1)
Purchased power 25 48
CILCORP (57) (92)
EEI 1 8
- --------------------------------------------------------------------------------
Total variation in fuel and purchased power (24) (42)
- --------------------------------------------------------------------------------
Change in electric margin $ 14 $ 105
- --------------------------------------------------------------------------------
Electric margin increased $14 million for the three months and $105 million
for the six months ended June 30, 2003, compared to the same periods in 2002.
Increases in electric margin in the second quarter and first six months of 2003
were primarily attributable to the acquisition of CILCORP, and increased
interchange margins, partially offset by unfavorable weather conditions.
CILCORP's electric margin for the three and six months ended June 30, 2003 was
$67 million and $112 million, respectively. Interchange margins increased
approximately $18 million in the second quarter and approximately $60 million in
the first six months of 2003 due to improved power prices in the energy markets
and solid low-cost generation availability. Average power prices increased to
approximately $36 per megawatthour in the first six months of 2003 from
approximately $24 per megawatthour in the first six months of 2002.
The unfavorable weather conditions were primarily due to mild early summer
weather in the second quarter of 2003 versus warmer than normal conditions in
the same period in 2002. In Ameren's pre-acquisition service territory,
weather-sensitive residential and commercial electric kilowatthour sales
declined 17% and 8%, respectively, in the second quarter of 2003 (year-to-date -
1% and 2%, respectively) compared to the second quarter of 2002. Cooling degree
days were approximately 30% and 40% less in the second quarter of 2003 compared
to normal and the prior year period, respectively.
Rate reductions of $50 million and $30 million effective April 1, 2002 and
2003, respectively, relating to the 2002 rate case settlement in Missouri, also
negatively impacted electric revenues in the first six months of 2003. Revenues
will be further negatively affected by the settlement of the Missouri electric
rate case, due to an additional $30 million of annual electric rate reduction
effective April 1, 2004.
The growth and other line item includes the sale of emission credits at
AmerenUE. The sale of emission credits at AmerenUE increased in the second
quarter of 2003 by $4 million, but decreased in the first six months of 2003 by
$9 million, compared to the same periods in 2002. In addition, industrial
electric kilowatthour sales increased approximately 6% in the second quarter of
2003 in our pre-acquisition
22
service territory.
EEI sales decreased compared to the prior periods due to lower emission
credits and decreased sales to its principal customer, which also resulted in a
decrease in fuel and purchased power. EEI's sales of emission credits were $10
million in the second quarter and first six months of 2003 (2002 - second
quarter and year-to-date - $38 million).
Fuel and purchased power increased in the second quarter and first six
months of 2003 compared to the prior period due to increased kilowatthour sales
related primarily to the addition of CILCORP to our results. Excluding the
addition of CILCORP, fuel and purchased power costs decreased approximately $33
million in the second quarter and $50 million in the first six months of 2003
due to greater availability of low-cost generation.
During 2002, we adopted the provisions of Emerging Issues Task Force (EITF)
Issue 02-3, "Issues Involved in Accounting for Derivative Contracts Held for
Trading Purposes and Contracts Involved in Energy Trading and Risk Management
Activities," that required revenues and costs associated with certain energy
contracts to be shown on a net basis in the income statement. The operating
revenues and costs that were netted for the three and six months ended June 30,
2002 were $133 million and $374 million, respectively, which reduced interchange
and other revenues and purchased power and other costs by equal amounts. See
Note 1 - Summary of Significant Accounting Policies to our Consolidated
Financial Statements under Item 1 of Part I of this report for further
information.
Gas Operations
Our gas margin increased $11 million in the second quarter of 2003 and $36
million in the first six months of 2003, compared to the same periods in the
prior year. The increases in margin were primarily due to the acquisition of
CILCORP (second quarter - $16 million; year-to-date - $36 million).
Other Operating Expenses
Other Operations and Maintenance
Other operations and maintenance expenses increased $19 million in the
second quarter and $56 million in the first six months of 2003 compared to the
prior year periods, primarily due to the addition of CILCORP's other operations
and maintenance expenses (second quarter - $44 million; year-to-date - $73
million), CILCORP's transition costs and higher employee benefit costs primarily
related to higher healthcare and pension costs. The increases in expense were
partially offset by lower labor costs related to our voluntary employee
retirement program instituted at the end of 2002 and lower maintenance costs at
our power plants primarily due to the number and timing of outages.
Depreciation and Amortization
Depreciation and amortization expenses increased $26 million in the second
quarter and $43 million in the first six months of 2003, compared to the
year-ago periods. The increase was primarily due to the addition of CILCORP's
depreciation and amortization (second quarter - $21 million; year-to-date - $35
million), and the completion of four combustion turbine generating units in the
third and fourth quarters of 2002 at Generating Company. The increased
depreciation and amortization expense was partially offset by a $5 million
reduction in depreciation expense in the first quarter of 2003 resulting from a
$20 million annual depreciation reduction of depreciation rates. This reduction
was based on the updated analysis of asset values, service lives and accumulated
depreciation levels that were required by our 2002 Missouri electric rate case
settlement.
23
Income Taxes
Income tax expense decreased $6 million in the second quarter of 2003, as
compared to the second quarter of 2002, primarily due to lower pre-tax income
and a lower effective tax rate. Income tax expense increased $8 million in the
first six months of 2003, as compared to the same period in 2002, primarily due
to higher pre-tax income.
Other Taxes
Other taxes expense increased $8 million in the second quarter and $18
million in the first six months of 2003, compared to the year-ago periods,
primarily due to the acquisition of CILCORP (second quarter - $9 million;
year-to-date - $17 million).
Other Income and Deductions
Other income and deductions (excluding income taxes) increased $32 million
in the second quarter of 2003 and $34 million in the first six months of 2003,
compared to the same periods in the prior year, primarily due to expensing of
economic development and energy assistance programs required in the Missouri
electric rate case settlement in 2002 ($26 million) and an increase in the
minority interest expense related to EEI's higher contribution in June 2002. See
Note 7 - Miscellaneous, Net to our Consolidated Financial Statements under Item
1 of Part I of this report for further information.
Interest
Interest expense increased $17 million in the second quarter and $33
million in the first six months of 2003, compared to the year-ago periods,
primarily due to the assumption of CILCORP debt (second quarter - $12 million;
year-to-date - $22 million). In addition, interest expense was higher in 2003
due to the interest expense component associated with the $345 million of
adjustable conversion rate equity security units we issued in March 2002, and
Generating Company's issuance of $275 million of 7.95% notes in June 2002,
partially offset by lower interest rates.
LIQUIDITY AND CAPITAL RESOURCES
Operating
Our cash flows provided by operating activities totaled $430 million for
the first six months of 2003, compared to $346 million for the same period in
2002. Cash provided by operating activities increased in 2003, primarily as a
result of higher electric and gas margins and the timing of receipts on accounts
receivable.
The tariff-based gross margins of our rate-regulated utility operating
companies continue to be our principal source of cash from operating activities.
Our diversified retail customer mix of primarily rate-regulated residential,
commercial and industrial classes and a commodity mix of gas and electric
service provide a reasonably predictable source of cash flows. In addition, we
plan to utilize short-term debt to support normal operations and other temporary
capital requirements.
Investing
Our net cash used in investing activities was $816 million in the first six
months of 2003, compared to $411 million for the same period in 2002. The
increase over the prior year period was primarily related to the cash paid of
$489 million for the acquisition of CILCORP on January 31, 2003 and Medina
Valley on February 4, 2003.
In addition, in the first six months of 2003, construction expenditures in
our rate-regulated operations were $300 million (2002 - $289 million), primarily
related to various upgrades at our power plants.
24
Construction expenditures in our non rate-regulated operations of $32 million in
the first six months of 2003 decreased from the first six months of 2002 ($112
million) due to reduced construction of combustion turbine generating units in
2002. Capital expenditures primarily relating to our rate-regulated operations
are expected to approximate $675 million in 2003.
We continually review our generation portfolio and expected electrical
needs, and as a result, we could modify our plan for generation capacity, 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
significant capital expenditures or losses being incurred, which could be
material.
Financing
Our cash flows used in financing activities totaled $141 million in the
first six months of 2003 as compared to our cash flows provided by financing
activities of $148 million in the first six months of 2002. Our principal
financing activities for the first six months of 2003 included the redemptions
of short-term and long-term debt, as well as payments of dividends, partially
offset by issuances of long-term debt and common stock. In addition to the
activities above, the first six months of 2002 also included issuances of
adjustable conversion rate equity security units.
Ameren Corporation and AmerenUE are authorized by the SEC under the PUHCA
to have up to an aggregate of $1.5 billion and $1 billion, respectively, of
short-term unsecured debt instruments outstanding at any time. In addition,
AmerenCIPS, AmerenCILCO and CILCORP have PUHCA authority to have up to an
aggregate of $250 million each of short-term unsecured debt instruments
outstanding at any time. Generating Company is authorized by the Federal Energy
Regulatory Commission (FERC) to have up to $300 million of short-term debt
outstanding at any time.
Short-Term Debt and Liquidity
Short-term debt consists of commercial paper and bank loans (maturities
generally within 1 to 45 days). At June 30, 2003, Ameren had committed credit
facilities, expiring at various dates through 2005, totaling $772 million,
excluding AmerenCILCO facilities of $59 million, EEI facilities of $41 million
and nuclear fuel lease facilities of $120 million. Ameren's $772 million of
committed credit facilities were available for use by two of our rate-regulated
subsidiaries, AmerenUE and AmerenCIPS, and Ameren Services Company through our
utility money pool arrangement, and $600 million of this amount may be used by
Ameren Corporation, and most of our non rate-regulated subsidiaries including,
but not limited to, Resources Company, Generating Company, Marketing Company,
AmerenEnergy Fuels and Services Company and AmerenEnergy through our
non-regulated subsidiary money pool arrangement. AmerenCILCO could also access
up to $600 million of these facilities through direct borrowings from Ameren
Corporation, subject to reduction based on use by our affiliates and subject to
a $250 million intercompany borrowing restriction pursuant to AmerenCILCO's
financing authority under the PUCHCA. Subject to the receipt of regulatory
approval, which is being pursued, AmerenCILCO will participate in the utility
money pool arrangement. These committed credit facilities are used to support
our commercial paper programs under which $177 million was outstanding at June
30, 2003. At June 30, 2003, $595 million was unused and available under these
committed credit facilities.
In July 2003, Ameren Corporation entered into two new credit agreements for
$470 million in revolving credit facilities to be used for general corporate
purposes, including the support of our commercial paper programs. The $470
million in new facilities includes a $235 million 364-day revolving credit
facility and a $235 million three-year revolving credit facility. These new
credit facilities replaced Ameren Corporation's existing $270 million 364-day
revolving credit facility, which matured in July 2003 and a $200 million
facility, which would have matured in December 2003. The new credit facilities
contain provisions which require us to meet minimum Employee Retirement Income
Security Act (ERISA) funding requirements for our pension plan. The prior credit
facilities included more restrictive provisions related to the funded status of
our pension plan, which are not present in the new facilities. In addition, in
25
July 2003, Ameren Corporation entered into an amendment of an existing $130
million multi-year credit facility that similarly modified the ERISA-related
provisions in this facility. As a result, all of Ameren Corporation's facilities
require us to meet minimum ERISA funding requirements, but do not otherwise
limit the underfunded status of our pension plan. At July 31, 2003, all of such
borrowing capacity under these facilities was available.
We also have two bank credit agreements totaling $41 million that expire in
2004 at EEI. At June 30, 2003, $41 million was unused and available under these
committed credit facilities.
AmerenUE also has a lease agreement that provides for the financing of
nuclear fuel. At June 30, 2003, the maximum amount that could be financed under
the agreement was $120 million. At June 30, 2003, $93 million was financed under
the lease.
We rely on access to short-term and long-term capital markets as a
significant source of funding for capital requirements not satisfied by our
operating cash flows. Our inability to raise capital on favorable terms,
particularly during times of uncertainty in the capital markets, could
negatively impact our ability to maintain and grow our businesses. Based on our
current credit ratings, we believe that we will continue to have access to the
capital markets. However, events beyond our control may create uncertainty in
the capital markets such that our cost of capital would increase or our ability
to access the capital markets would be adversely affected.
Financial Agreement Provisions and Covenants
Our financial agreements include customary default or cross default
provisions that could impact the continued availability of credit or result in
the acceleration of repayment. The majority of Ameren's committed credit
facilities require the borrower to represent in connection with any borrowing
under the facility that no material adverse change has occurred since certain
dates. Ameren's financing arrangements do not contain credit rating triggers,
except for three funded bank term loans at AmerenCILCO totaling $105 million at
June 30, 2003.
At June 30, 2003, Ameren Corporation and its subsidiaries were in
compliance with their financial agreement provisions and covenants.
Debt Issuances and Redemptions
On February 10, 2003, AmerenCILCO repaid $25 million first mortgage bonds
6.82% Series which matured on that date.
In March 2003, AmerenUE issued $184 million of 5.50% Senior Secured Notes
due March 15, 2034. AmerenUE received net proceeds after fees of $180 million,
which, along with other funds, were used to redeem $104 million principal amount
of outstanding 8.25% first mortgage bonds due October 15, 2022, at a redemption
price of 103.61% of par, plus accrued interest, in April 2003, prior to
maturity, and to repay short-term debt incurred to pay at maturity $75 million
principal amount of 8.33% first mortgage bonds that matured in December 2002.
In April 2003, AmerenUE issued $114 million of 4.75% Senior Secured Notes
due April 1, 2015. AmerenUE received net proceeds after fees of $113 million,
which, along with other funds, were used to redeem $85 million principal amount
of outstanding 8.00% first mortgage bonds due December 15, 2022, at a redemption
price of 103.38% of par, plus accrued interest, prior to maturity, and to reduce
short-term debt.
On April 1, 2003, AmerenCIPS repaid $40 million first mortgage bonds 6.375%
Series Z which matured on that date. AmerenCIPS also redeemed, in April 2003,
prior to maturity and at par, its $50 million first mortgage bonds 7.5% Series X
due July 1, 2007.
26
In April 2003, three series of AmerenCILCO's first mortgage bonds were
redeemed prior to maturity. These included AmerenCILCO's $65 million principal
amount 8.20% series due January 15, 2022, at a redemption price of 103.29% and
two 7.8% series totaling $10 million principal amount due February 9, 2023, at a
redemption price of 103.90%.
On June 30, 2003, AmerenEnergy Medina Valley Cogen, LLC, an indirect
subsidiary of AmerenEnergy Medina Valley Cogen (No. 4), LLC, repaid, prior to
maturity, a $36 million, secured term loan with an effective interest rate of
7.65% and terminated two related interest rate swaps. This redemption eliminated
the outstanding bank debt at AmerenEnergy Medina Valley Cogen, LLC.
In July 2003, AmerenUE issued $200 million of 5.10% Senior Secured Notes
due August 1, 2018. AmerenUE received net proceeds after fees of $198 million
which, along with other funds were used to repay short-term debt incurred to
fund the maturity of $100 million principal amount 7.65% first mortgage bonds
due July 15, 2003 and to repay $21 million of other short-term debt. The
remaining proceeds will be used to redeem and refinance, prior to maturity, $75
million principal amount of outstanding 7.15% first mortgage bonds due August 1,
2023 at a redemption price of 103.01% of par, plus accrued interest, in August
2003.
See also Note 6 - Debt and Equity Financings to our Consolidated Financial
Statements under Item 1 of Part I of this report for further information about
financings during the first six months of 2003.
Dividends
Our Board of Directors does not set specific targets or payout parameters
when declaring common stock dividends. However, the Board considers various
issues, including our historic earnings and cash flow; projected earnings; cash
flow and potential cash flow requirements; dividend payout rates at other
utilities; return on investments with similar risk characteristics; and overall
business considerations. On April 22, 2003, our Board of Directors declared a
quarterly common stock dividend of 63.5 cents per share that was paid on June
30, 2003 to shareholders of record on June 11, 2003.
Off-Balance Sheet Arrangements
At June 30, 2003, neither Ameren Corporation, nor any of its subsidiaries,
had any off-balance sheet financing arrangements, other than operating leases
entered into in the ordinary course of business.
OUTLOOK
We believe there will be challenges to earnings in 2003 and beyond due to
industry-wide trends and company-specific issues. The following are expected to
put pressure on earnings in 2003 and beyond:
o Weak economic conditions, which impacts native load demand;
o Power prices in the Midwest will impact the amount of revenues we can
generate by marketing any excess power into the interchange markets.
Long-term power prices continue to be generally soft in the Midwest,
despite the fact that short-term power prices have strengthened
significantly from the prior year in the first six months of 2003 due
primarily to higher prices for natural gas;
o A rate settlement approved in 2002 by the Missouri Public Service
Commission (MoPSC) that required electric rate reductions of $50 million on
April 1, 2002, and $30 million on April 1, 2003 with an additional $30
million reduction required for April 1, 2004;
o Fixed electric rates in our Illinois service territory;
o The adverse effects of rising employee benefit costs, higher insurance
costs and increased security costs associated with additional measures we
have taken, or may have to take, at our Callaway nuclear plant related to
world events;
o The incremental dilution from equity issued in both 2002 and 2003; and
o An assumed return to more normal weather patterns relative to 2002.
27
In late 2002, we announced the following actions to mitigate the effect of
these challenges:
o A voluntary retirement program that was accepted by approximately 550
employees;
o Modifications to retiree employee benefit plans to increase co-payments and
limit our overall cost;
o A wage freeze in 2003 for all management employees;
o Suspension of operations at a 1940's-era generating plant to reduce
operating costs; and
o Reductions of 2003 expected capital expenditures.
We are pursuing annual gas rate increases of approximately $34 million in
Illinois and $27 million in Missouri. See Note 3 - Rate and Regulatory Matters
to our Consolidated Financial Statements under Item 1 of Part I of this report
for additional information. We are also considering additional actions,
including modifications to active employee benefits, further staffing
reductions, accelerating synergy opportunities related to the CILCORP
acquisition and other initiatives.
International Brotherhood of Electrical Workers (IBEW) and the
International Union of Operating Engineers (IUOE) labor agreements for eleven
bargaining units covering 52% of our entire workforce expired between April 1
and July 1, 2003. The principal issues being negotiated are wages, work rules
and our proposal to change the employee medical benefits program to require
employees to pay for a greater portion of their benefit coverage.
During July 2003, after engaging in extensive negotiations with the
collective bargaining units, we finalized new tentative agreements with seven of
the bargaining units with terms expiring in 2006. The membership of three of the
bargaining units have ratified the agreements with respect to wages and work
rules and the membership of four bargaining units is expected to vote on their
new agreement in the third quarter of 2003. Changes to the employee medical
benefits program have been agreed to with a joint bargaining committee
representing all unions; however, the changes cannot be implemented without
ratification by a majority of the collective membership of all bargaining units.
We are unable to predict whether the agreements will be ratified or what action,
if any, the collective bargaining units will take in the event the agreements
are not ratified or the response of other union-represented employees to any
action by its employees. We are still negotiating as to wages and work rules
with three bargaining units, which represent approximately 29% of our workforce.
We are unable to determine what, if any, impact these labor matters could have
on our future financial condition, results of operations or liquidity.
At December 31, 2002, we recorded a minimum pension liability of $102
million, after taxes, which resulted in a charge to Accumulated Other
Comprehensive Income (Loss)(OCI) and a reduction in stockholders' equity. Based
on changes in interest rates, we may need to change our actuarial assumptions
for our pension plan at December 31, 2003, which could result in a requirement
to record an additional minimum pension liability.
In the ordinary course of business, we evaluate strategies to enhance our
financial position, results of operations and liquidity. These strategies may
include potential acquisitions, divestitures, and opportunities to reduce costs
or increase revenues, and other strategic initiatives in order to increase
shareholder value. We are unable to predict which, if any, of these initiatives
will be executed, as well as the impact these initiatives may have on our future
financial position, results of operations or liquidity.
REGULATORY MATTERS
See Note 3 - Rate and Regulatory Matters to our Consolidated Financial
Statements under Item 1 of Part I of this report for information.
28
ACCOUNTING MATTERS
Critical Accounting Policies
Preparation of the financial statements and related disclosures in
compliance with generally accepted accounting principles requires the
application of appropriate technical accounting rules and guidance, as well as
the use of estimates. Our application of these policies involves judgments
regarding many factors, which, in and of themselves, could materially impact the
financial statements and disclosures. Refer to Management's Discussion and
Analysis of Financial Condition and Results of Operations that is incorporated
by reference from our 2002 Annual Report to Shareholders into our Annual Report
on Form 10-K for the period ended December 1, 2002, as amended by Form 10-K/A,
for a discussion of the critical accounting policies that we believe are most
difficult, subjective or complex. In the discussion below, we have outlined an
additional accounting policy that has developed due to our acquisition of
CILCORP. A future change in the assumptions or judgments applied in determining
the following matter, among others, could have a material impact on future
financial results.
Accounting Policy Uncertainties Affecting Application
- ----------------- -----------------------------------
Leveraged Leases o Market conditions of the industry of the leased
We account for our investment in leveraged asset that might affect the residual value at the
leases in accordance with SFAS 13, "Accounting end of the lease terms. This would include: the
for Leases." As required by SFAS 13, we review real estate markets where each of the assets are
the estimated residual value as well as all located; the rail industry; the aerospace industry;
other important assumptions affecting estimated and energy market where the asset is located.
total net income from the leases. SFAS 13
requires the rate of return and total income of
a lease to be recalculated if there is a permanent
decline in the estimated residual value
below the value currently used to calculate
income.
Basis for Judgment
We determine whether the residual value has been "permanently impaired"
based on an internal review as well as periodic third party review of the
residual value.
Impact of Future Accounting Pronouncements
See Note 1 - Summary of Significant Accounting Policies to our Consolidated
Financial Statements under Item 1 of Part I of this report for information.
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk.
Market risk represents the risk of changes in value of a physical asset or
a financial instrument, derivative or non-derivative, caused by fluctuations in
market variables (e.g., interest rates, etc.). The following discussion of our
risk management activities includes "forward-looking" statements that involve
risks and uncertainties. Actual results could differ materially from those
projected in the "forward-looking" statements. We handle market risks in
accordance with established policies, which may include entering into various
derivative transactions. In the normal course of business, we also face risks
that are either non-financial or non-quantifiable. Such risks principally
include business, legal and operational risks and are not represented in the
following discussion.
29
Our risk management objective is to optimize our physical generating assets
within prudent risk parameters. Our risk management policies are set by a Risk
Management Steering Committee, which is comprised of senior-level Ameren
officers.
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated
with both long-term and short-term variable-rate debt and fixed-rate debt,
commercial paper, auction-rate long-term debt and auction-rate preferred stock.
We manage our interest rate exposure by controlling the amount of these
instruments we hold within our total capitalization portfolio and by monitoring
the effects of market changes in interest rates.
Utilizing our debt outstanding at June 30, 2003, if interest rates
increased by 1%, our annual interest expense would increase by approximately $11
million and net income would decrease by approximately $7 million. The model
does not consider the effects of the reduced level of potential overall economic
activity that would exist in such an environment. In the event of a significant
change in interest rates, management would likely take actions to further
mitigate our exposure to this market risk. However, due to the uncertainty of
the specific actions that would be taken and their possible effects, the
sensitivity analysis assumes no change in our financial structure.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties
fail to perform as contracted. New York Mercantile Exchange (NYMEX) traded
futures contracts are supported by the financial and credit quality of the
clearing members of the NYMEX and have nominal credit risk. On all other
transactions, we are exposed to credit risk in the event of nonperformance by
the counterparties in the transaction.
Our physical and financial instruments are subject to credit risk
consisting of trade accounts receivables and executory contracts with market
risk exposures. The risk associated with trade receivables is mitigated by the
large number of customers in a broad range of industry groups comprising our
customer base. No customer represents greater than 10% of our accounts
receivable. Our revenues are primarily derived from sales of electricity and
natural gas to customers in Missouri and Illinois. We analyze each
counterparty's financial condition prior to entering into sales, forwards,
swaps, futures or option contracts and monitor counterparty exposure associated
with our leveraged leases. As of June 30, 2003, we had approximately $168
million invested in leveraged leases, primarily at CILCORP. We also establish
credit limits for these counterparties and monitor the appropriateness of these
limits on an ongoing basis through a credit risk management program which
involves daily exposure reporting to senior management, master trading and
netting agreements, and credit support management such as letters of credit and
parental guarantees.
Equity Price Risk
Our costs of providing non-contributory defined benefit retirement and
post-retirement benefit plans are dependent upon a number of factors, such as
the rates of return on plan assets, discount rate, the rate of increase in
health care costs and contributions made to the plans. The market value of our
plan assets has been affected by declines in the equity market since 2000 for
the pension and post-retirement plans. As a result, at December 31, 2002, we
recognized an additional minimum pension liability as prescribed by SFAS No. 87,
"Employers' Accounting for Pensions." The liability resulted in a reduction to
equity as a result of a charge to OCI of $102 million, net of taxes. The amount
of the liability was the result of asset returns experienced through 2002,
interest rates and our contributions to the plans during 2002. The minimum
pension liability did not change at June 30, 2003. In future years, the
liability recorded, the costs reflected in net income, or OCI, or cash
contributions to the plans could increase materially without a recovery in
equity markets in excess of our assumed return on plan assets. If the fair value
of the plan assets were to grow and exceed the accumulated benefit obligations
in the future, then the recorded liability would be reduced and a corresponding
amount of equity would be restored in the Consolidated Balance Sheet.
30
We also maintain trust funds, as required by the Nuclear Regulatory
Commission and Missouri and Illinois state laws, to fund certain costs of
nuclear decommissioning. By maintaining a portfolio that includes long-term
equity investments, we seek to maximize the returns to be utilized to fund
nuclear decommissioning costs. However, the equity securities included in our
portfolio are exposed to price fluctuations in equity markets and the
fixed-rate, fixed-income securities are exposed to changes in interest rates. We
actively monitor our portfolio by benchmarking the performance of our
investments against certain indices and by maintaining, and periodically
reviewing, established target allocation percentages of the assets of our trusts
to various investment options. Our exposure to equity price market risk is, in
large part, mitigated, due to the fact that we are currently allowed to recover
decommissioning costs in our rates.
Fair Value of Contracts
We utilize derivatives principally to manage the risk of changes in market
prices for natural gas, fuel, electricity and emission credits. Price
fluctuations in natural gas, fuel and electricity cause:
o an unrealized appreciation or depreciation of our firm commitments to
purchase or sell when purchase or sales prices under the firm commitment
are compared with current commodity prices;
o market values of fuel and natural gas inventories or purchased power to
differ from the cost of those commodities in inventory under firm
commitment; and
o actual cash outlays for the purchase of these commodities to differ from
anticipated cash outlays.
The derivatives that we use to hedge these risks are dictated by risk
management policies and include forward contracts, futures contracts, options
and swaps. We continually assess our supply and delivery commitment positions
against forward market prices and internally forecast forward prices and modify
our exposure to market, credit and operational risk by entering into various
offsetting transactions. In general, we believe these transactions serve to
reduce our price risk. See Note 4 - Derivative Financial Instruments to our
Consolidated Financial Statements under Item 1 of Part I of this report for
further information.
The following table summarizes the favorable (unfavorable) changes in the
fair value of all contracts marked-to-market during the three and six months
ended June 30, 2003:
- ---------------------------------------------------------------------------------------------------------
Three Six
months months
- ---------------------------------------------------------------------------------------------------------
Fair value of contracts at beginning of period, net $ - $ 3
Contracts which were realized or otherwise settled during the period 5 (4)
Changes in fair values attributable to changes in valuation techniques and - -
assumptions
Fair value of new contracts entered into during the period - -
Other changes in fair value (4) 2
- ----------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at end of period, net $ 1 $ 1
- ----------------------------------------------------------------------------------------------------------
31
Maturities of contracts as of June 30, 2003 were as follows:
- ----------------------------------------------------------------------------------------------------------
Maturity Maturity in
less than Maturity Maturity excess of 5 Total fair
Sources of fair value 1 year 1-3 years 4-5 years years value (a)
- ----------------------------------------------------------------------------------------------------------
Prices actively quoted $ - $ - $ - $ - $ -
Prices provided by other external
sources (b) - (1) (1) - (2)
Prices based on models and other
valuation methods (c) 3 1 (1) - 3
- ---------------------------------------------------------------------------------------------------------
Total $ 3 $ - $ (2) $ - $ 1
- ---------------------------------------------------------------------------------------------------------
(a) Contracts of less than $1 million were with non-investment-grade rated
counterparties.
(b) Principally power forward values based on NYMEX prices for over-the-counter
contracts and natural gas swap values based primarily on Inside FERC.
(c) Principally coal and sulfur dioxide option values based on a Black-Scholes
model that includes information from external sources and our estimates.
Also includes power forward values based on our estimates.
ITEM 4. Controls and Procedures.
(a) Evaluation of Disclosure Controls and Procedures
As of June 30, 2003, the principal executive officer and principal
financial officer of Ameren have evaluated the effectiveness of the design and
operation of Ameren's disclosure controls and procedures (as defined in Rules
13a - 15(e) and 15d - 15 (e) of the Securities Exchange Act of 1934, as amended
(Exchange Act)). Based upon that evaluation, the principal executive officer and
principal financial officer of Ameren have concluded that such disclosure
controls and procedures are effective in timely alerting them to any material
information relating to Ameren and its consolidated subsidiaries, which is
required to be included in Ameren's reports filed or submitted with the SEC
under the Exchange Act.
(b) Change in Internal Controls
There has been no significant change in Ameren's internal control over
financial reporting that occurred during Ameren's most recent fiscal quarter
that has materially affected, or is reasonably likely to materially affect,
Ameren's internal control over financial reporting.
FORWARD-LOOKING STATEMENTS
Statements made in this report which are not based on historical facts are
"forward-looking" and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
"forward-looking" statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans, strategies, objectives, events, conditions and
financial performance. In connection with the "safe harbor" provisions of the
Private Securities Litigation Reform Act of 1995, we are providing this
cautionary statement to identify important factors that could cause actual
results to differ materially from those anticipated. The following factors, in
addition to those discussed elsewhere in this report and in subsequent
securities filings and others, could cause results to differ materially from
management expectations as suggested by such "forward-looking" statements:
o the effects of the stipulation and agreement relating to the AmerenUE
Missouri electric excess earnings complaint case and other regulatory
actions, including changes in regulatory policy;
o changes in laws and other governmental actions, including monetary and
fiscal policies;
o the impact on us of current regulations related to the opportunity for
customers to choose alternative energy suppliers in Illinois;
32
o the effects of increased competition in the future due to, among other
things, deregulation of certain aspects of our business at both the state
and federal levels;
o the effects of participation in a FERC-approved Regional Transmission
Organization, including activities associated with the Midwest Independent
System Operator;
o availability and future market prices for fuel for the production of
electricity, such as coal and natural gas, purchased power, electricity and
natural gas for distribution, including the use of financial and derivative
instruments, the volatility of changes in market prices and the ability to
recover increased costs;
o average rates for electricity in the Midwest;
o business and economic conditions;
o the impact of the adoption of new accounting standards on the application
of appropriate technical accounting rules and guidance;
o interest rates and the availability of capital;
o actions of rating agencies and the effects of such actions;
o weather conditions;
o generation plant construction, installation and performance;
o operation of nuclear power facilities and decommissioning costs;
o the effects of strategic initiatives, including acquisitions and
divestitures;
o the impact of current environmental regulations on utilities and generating
companies and the expectation that more stringent requirements will be
introduced over time, which could potentially have a negative financial
effect;
o future wages and employee benefit costs, including changes in returns of
benefit plan assets;
o disruptions of the capital markets or other events making our access to
necessary capital more difficult or costly;
o competition from other generating facilities, including new facilities that
may be developed in the future;
o difficulties in integrating CILCO with Ameren's other businesses;
o changes in the coal markets, environmental laws or regulations or other
factors adversely impacting synergy assumptions in connection with the
CILCORP acquisition;
o cost and availability of transmission capacity for the energy generated by
our generating facilities or required to satisfy energy sales made by
Ameren; and
o legal and administrative proceedings.
Given these uncertainties, undue reliance should not be placed on these
forward-looking statements. Except to the extent required by the federal
securities laws, we undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
33
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings.
On June 18, 2003, twenty retirees and surviving spouses of retirees of
Ameren Corporation or our predecessors or subsidiaries (the plaintiffs) filed a
complaint in the U.S. District Court, Southern District of Illinois, against
Ameren, and our subsidiaries, Union Electric Company, operating as AmerenUE,
Central Illinois Public Service Company, operating as AmerenCIPS, Ameren Energy
Resources Company, Ameren Energy Generating Company and Ameren Services Company,
and against our Retiree Medical Plan (the defendants). The retirees were members
of various local labor unions of the International Brotherhood of Electrical
Workers (IBEW) and the International Union of Operating Engineers (IUOE). The
complaint alleges the following:
o the labor organizations which represented the plaintiffs have historically
negotiated retiree medical benefits with the defendants and that pursuant
to the negotiated collective bargaining agreements and other negotiated
documents, the plaintiffs are guaranteed medical benefits at no cost or at
a fixed maximum cost during their retirement;
o Ameren has unilaterally announced that, beginning in 2004, retirees must
pay a portion of their own health care premiums and either an increasing
portion of their dependents' premiums or newly imposed dependents'
premiums, and that surviving spouses will be paying increased amounts for
their medical benefits;
o the defendants' actions deprive the plaintiffs of vested benefits and thus
violate the Employee Retirement Income Security Act and the Labor
Management Relations Act of 1947, and constitute a breach of the
defendants' fiduciary duties; and
o the defendants are estopped from changing the plan benefits.
The plaintiffs have filed the complaint on behalf of themselves, other
similarly situated former non-management employees and their surviving spouses
who retired from January 1, 1992 through October 1, 2002, and on behalf of all
subsequent non-management retirees and their surviving spouses whose vested
medical benefits are reduced or are threatened with reduction. The plaintiffs
seek to have this lawsuit certified as a class action, seek injunctive relief
and declaratory relief, seek actual damages for any amounts they are made to pay
as a result of the defendants' actions, and seek payment of attorney fees and
costs. On August 11, 2003, the defendants filed motions to dismiss various
counts of the complaint. We are unable to predict the outcome of this lawsuit or
the impact of the outcome on our financial position, results of operations or
liquidity.
Reference is made to Note 3 to the Notes to Consolidated Financial
Statements in our Form 10-Q for the quarterly period ended March 31, 2003 for a
discussion of the Missouri Supreme Court's opinion issued in April 2003
upholding the adoption of affiliate rules by the Missouri Public Service
Commission for Missouri's gas and electric utilities. AmerenUE had originally
appealed the adoption of the asymmetric pricing provisions contained in the
affiliate rules. In May 2003, the Missouri Supreme Court denied AmerenUE's
Motion for Reconsideration of its April 2003 opinion which makes the affiliate
rules applicable to AmerenUE. We do not expect these rules to have a material
adverse impact on our future financial position, cash flows or results of
operations.
Reference is made to Note 14 to the Notes to Consolidated Financial
Statements in our 2002 Annual Report to Shareholders which is incorporated by
reference into Item 8. "Financial Statements and Supplementary Data" in Part II
of our 2002 Annual Report on Form 10-K (as amended by Form 10-K/A), to Note 7
under Item 8. "Financial Statements and Supplementary Data" in Part II of the
2002 Annual Report on Form 10-K of our subsidiaries, CILCORP Inc. and Central
Illinois Light Company, operating as AmerenCILCO, and to Item 1. "Legal
Proceedings" in Part II of our Form 10-Q for the quarterly period ended March
31, 2003, for a discussion of a number of lawsuits that name our subsidiaries,
AmerenCIPS, AmerenUE, AmerenCILCO and us (which we refer to as the Ameren
companies), along with numerous other parties, as defendants that have been
filed by plaintiffs claiming varying degrees of injury from asbestos exposure.
Since the filing of our Form 10-Q for the quarterly period ended March 31, 2003,
34
eleven additional lawsuits have been filed against the Ameren companies. These
lawsuits, like the previous cases, were mostly filed in the Circuit Court of
Madison County in Illinois, involve a large number of total defendants and seek
unspecified damages in excess of $50,000, which, if proved, typically would be
shared among the named defendants. Also since the filing of our Form 10-Q for
the quarterly period ended March 31, 2003, the Ameren companies have settled one
case. To date, a total of 164 asbestos-related lawsuits have been filed against
the Ameren companies, of which 84 are pending, 17 have been settled and 63 have
been dismissed. We believe that the final disposition of these proceedings will
not have a material adverse effect on our financial position, results of
operations or liquidity.
Note 3 - Rate and Regulatory Matters to our Consolidated Financial
Statements under Item 1 of Part I of this report contains additional information
on legal and administrative proceedings which is incorporated by reference under
this item.
ITEM 4. Submission of Matters To a Vote of Security Holders.
At our annual meeting of stockholders held on April 22, 2003, the following
matters were presented to the meeting for a vote and the results of such voting
are as follows:
Item (1): Election of Directors.
Non-Voted
Name For Withheld Brokers<F1>
---- --- -------- ---------
William E. Cornelius 119,277,149 19,346,548 0
Clifford L. Greenwalt 134,924,430 3,699,267 0
Thomas A. Hays 135,025,530 3,598,167 0
Richard A. Liddy 134,422,688 4,201,009 0
Gordon R. Lohman 135,085,800 3,537,897 0
Richard A. Lumpkin 134,611,968 4,011,729 0
John Peters MacCarthy 135,077,727 3,545,970 0
Hanne M. Merriman 135,046,806 3,576,891 0
Paul L. Miller, Jr. 134,794,875 3,828,822 0
Charles W. Mueller 134,638,714 3,984,983 0
Douglas R. Oberhelman 134,492,968 4,130,729 0
Harvey Saligman 134,620,991 4,002,706 0
Item (2): Stockholder Proposal Relating to the Storage of Irradiated Fuel Rods at the Callaway
Nuclear Plant.
Non-Voted
For Against Abstain Brokers<F1>
--- ------- ------- ---------
12,904,334 88,363,511 7,711,721 46,020,667
<FN>
<F1> Broker shares included in the quorum but not voting on the item.
</FN>
ITEM 5. Other Information.
Ms. Hanne M. Merriman, a director of Ameren Corporation, died on July 4,
2003. No decision has been made as to who, if anyone, will be appointed to
replace Ms. Merriman.
Reference is made to Item 2. "Properties" in Part I of our 2002 Annual
Report on Form 10-K for a discussion of our membership in MAIN (Mid-America
Interconnected Network), which is one of the regional electric reliability
councils organized for coordinating the planning and operation of the nation's
bulk power supply. In response to the withdrawal notices filed by Commonwealth
Edison and Illinois
35
Power, also members of MAIN, AmerenUE, AmerenCIPS and AmerenCILCO provided
formal written notice to the MAIN Board of Directors on June 23, 2003 of their
intent to withdraw from MAIN effective January 1, 2005. These Ameren companies
intend to join another Regional Reliability Organization (RRO) prior to their
withdrawal from MAIN becoming effective. Until their withdrawal is effective,
they will continue to honor all of their obligations as members of MAIN. If
these Ameren companies do not join another RRO, they may withdraw their notice
of intent to withdraw from MAIN.
Any stockholder proposal intended for inclusion in the proxy material for
our 2004 annual meeting of stockholders must be received by us by November 15,
2003. In addition, under our By-Laws, stockholders who intend to submit a
proposal in person at an annual meeting, or who intend to nominate a director at
a meeting, must provide advance written notice along with other prescribed
information. In general, such notice must be received by our Secretary not later
than 60 nor earlier than 90 days prior to the anniversary of the preceding
year's annual meeting. For our 2004 annual meeting of stockholders, written
notice of any in-person stockholder proposal or director nomination must be
received not later than February 22, 2004 or earlier than January 23, 2004. Our
2004 annual meeting of stockholders is scheduled to be held on April 27, 2004.
ITEM 6. Exhibits and Reports on Form 8-K.
(a)(i) Exhibits filed herewith.
31.1 - Rule 13a -14(a)/15d-14(a) Certification of Principal
Executive Officer (required by Section 302 of the
Sarbanes-Oxley Act of 2002).
31.2 - Rule 13a-14(a)/15d-14(a) Certification of Principal
Financial Officer (required by Section 302 of the
Sarbanes-Oxley Act of 2002).
32.1 - Section 1350 Certification of Principal Executive Officer
(required by Section 906 of the Sarbanes-Oxley Act of 2002).
32.2 - Section 1350 Certification of Principal Financial Officer
(required by Section 906 of the Sarbanes-Oxley Act of 2002).
(a)(ii) Exhibits incorporated by reference.
4.1 - AmerenUE Company Order dated July 28, 2003 establishing the
5.10% Senior Secured Notes due 2018 (AmerenUE Form 8-K dated
July 28, 2003, Exhibit 4.2).
4.2 - Supplemental Indenture dated July 15, 2003 to Indenture of
Mortgage and Deed of Trust dated June 15, 1937, as amended,
from AmerenUE to The Bank of New York, as successor trustee,
relating to First Mortgage Bonds, Senior Notes Series DD,
5.10% due 2018 (AmerenUE Form 8-K dated July 28, 2003,
Exhibit 4.4).
(b) Reports on Form 8-K. Ameren Corporation filed the following reports on
Form 8-K during the quarterly period ended June 30, 2003:
-----------------------------------------------------------------------
Items Financial
Date of Report Reported Statements Filed
-----------------------------------------------------------------------
April 30, 2003 7, 9, 12 (a)
May 23, 2003 5, 7 None
May 30, 2003 5 None
(a) Unaudited consolidated operating statistics, consolidated
statement of income, consolidated balance sheet and consolidated
statement of cash flows for three months ended March 31, 2003 and
2002.
Note: Reports of Central Illinois Public Service Company on Forms 8-K,
10-Q and 10-K are on file with the SEC under File Number 1-3672.
36
Reports of Union Electric Company on Forms 8-K, 10-Q and 10-K are
on file with the SEC under File Number 1-2967.
Reports of AmerenEnergy Generating Company on Forms 8-K, 10-Q and
10-K are on file with the SEC under File Number 333-56594.
Reports of CILCORP Inc. on Forms 8-K, 10-Q and 10-K are on file
with the SEC under File Number 2-95569.
Reports of Central Illinois Light Company on Forms 8-K, 10-Q and
10-K are on file with the SEC under File Number 1-2732.
37
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
AMEREN CORPORATION
(Registrant)
By /s/ Martin J. Lyons
--------------------------
Martin J. Lyons
Vice President and Controller
(Principal Accounting Officer)
Date: August 14, 2003
38