UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
for the Quarterly Period Ended March 31, 2009
OR
for the transition period from to .
Commission
File Number
Exact name of registrant as specified in its charter;
State of Incorporation;
Address and Telephone Number
IRS Employer
Identification No.
Indicate by check mark whether the registrants: (1) have 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) have been subject to such filing requirements for the past 90 days.
Ameren Corporation
Union Electric Company
Central Illinois Public Service Company
Ameren Energy Generating Company
Central Illinois Light Company
Illinois Power Company
CILCORP Inc. has voluntarily filed all reports that it would have been required to file if it had been subject to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.
Indicate by check mark whether each registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
CILCORP Inc.
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.
Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
The number of shares outstanding of each registrant’s classes of common stock as of April 30, 2009, was as follows:
Common stock, $5 par value per share, held by Ameren
Corporation (parent company of the registrant) - 102,123,834
Common stock, no par value, held by Ameren
Corporation (parent company of the registrant) - 25,452,373
Common stock, no par value, held by Ameren Energy
Resources Company, LLC (parent company of the
registrant and subsidiary of Ameren
Corporation) - 2,000
Corporation (parent company of the registrant) - 1,000
Common stock, no par value, held by CILCORP Inc.
(parent company of the registrant and subsidiary of
Ameren Corporation) - 13,563,871
Corporation (parent company of the registrant) - 23,000,000
OMISSION OF CERTAIN INFORMATION
Ameren Energy Generating Company and CILCORP Inc. meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this form with the reduced disclosure format allowed under that General Instruction.
This combined Form 10-Q is separately filed by Ameren Corporation, Union Electric Company, Central Illinois Public Service Company, Ameren Energy Generating Company, CILCORP Inc., Central Illinois Light Company, and Illinois Power Company. Each registrant hereto is filing on its own behalf all of the information contained in this quarterly report that relates to such registrant. Each registrant hereto is not filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.
TABLE OF CONTENTS
GLOSSARY OF TERMS AND ABBREVIATIONS
Forward-looking Statements
PART I Financial Information
Item 1. Financial Statements (Unaudited)
Consolidated Statement of Income
Consolidated Balance Sheet
Consolidated Statement of Cash Flows
Statement of Income
Balance Sheet
Statement of Cash Flows
Combined Notes to Financial Statements
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4 and Item 4T. Controls and Procedures
PART II Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 6. Exhibits
Signatures
This Form 10-Q contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors included on page 7 of this Form 10-Q 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.
4
We use the words “our,” “we” or “us” with respect to certain information that relates to all Ameren Companies, as defined below. When appropriate, subsidiaries of Ameren are named specifically as we discuss their various business activities.
AERG - AmerenEnergy Resources Generating Company, a CILCO subsidiary that operates a non-rate-regulated electric generation business in Illinois.
AFS - Ameren Energy Fuels and Services Company, a Resources Company subsidiary that procures fuel and natural gas and manages the related risks for the Ameren Companies.
AITC - Ameren Illinois Transmission Company, an Ameren Corporation subsidiary that is engaged in the construction and operation of transmission assets in Illinois and is regulated by the FERC and the ICC.
Ameren - Ameren Corporation and its subsidiaries on a consolidated basis. In references to financing activities, acquisition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, the parent.
Ameren Companies - The individual registrants within the Ameren consolidated group.
Ameren Illinois Utilities - CIPS, IP and the rate-regulated electric and gas utility operations of CILCO.
Ameren Services - Ameren Services Company, an Ameren Corporation subsidiary that provides support services to Ameren and its subsidiaries.
APB - Accounting Principles Board.
ARB - Accounting Research Bulletin.
ARO - Asset retirement obligations.
Baseload - The minimum amount of electric power delivered or required over a given period of time at a steady rate.
Btu - British thermal unit, a standard unit for measuring the quantity of heat energy required to raise the temperature of one pound of water by one degree Fahrenheit.
Capacity factor - A percentage measure that indicates how much of an electric power generating unit’s capacity was used during a specific period.
CILCO - Central Illinois Light Company, a CILCORP subsidiary that operates a rate-regulated electric transmission and distribution business, a non-rate-regulated electric generation business through AERG, and a rate-regulated natural gas transmission and distribution business, all in Illinois, as AmerenCILCO. CILCO owns all of the common stock of AERG.
CILCORP - CILCORP Inc., an Ameren Corporation subsidiary that operates as a holding company for CILCO and a non-rate-regulated subsidiary.
CIPS - Central Illinois Public Service Company, an Ameren Corporation subsidiary that operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenCIPS.
CIPSCO - CIPSCO Inc., the former parent of CIPS.
CO2 - Carbon dioxide.
COLA - Combined construction and operating license application.
Cooling degree-days - The summation of positive differences between the mean daily temperature and a 65-degree Fahrenheit base. This statistic is useful for estimating electricity demand by residential and commercial customers for summer cooling.
CT - Combustion turbine electric generation equipment used primarily for peaking capacity.
Development Company - Ameren Energy Development Company, which was an Ameren Energy Resources Company subsidiary and parent of Genco, Marketing Company, AFS, and Medina Valley. It was eliminated in an internal reorganization in February 2008.
DOE - Department of Energy, a U.S. government agency.
DRPlus - Ameren Corporation’s dividend reinvestment and direct stock purchase plan.
EEI - Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary that operates non-rate-regulated electric generation facilities and FERC-regulated transmission facilities in Illinois. Prior to February 29, 2008, EEI was 40% owned by UE and 40% owned by Development Company. On February 29, 2008, UE’s 40% ownership interest and Development Company’s 40% ownership interest were transferred to Resources Company. The remaining 20% is owned by Kentucky Utilities Company.
EITF - Emerging Issues Task Force, an organization designed to assist the FASB in improving financial reporting through the identification, discussion and resolution of financial issues in keeping with existing authoritative literature.
EPA - Environmental Protection Agency, a U.S. government agency.
Equivalent availability factor - A measure that indicates the percentage of time an electric power generating unit was available for service during a period.
ERISA - Employee Retirement Income Security Act of 1974, as amended.
Exchange Act - Securities Exchange Act of 1934, as amended.
FAC - A fuel and purchased power cost recovery mechanism that allows UE to recover through customer rates 95% of changes in fuel (coal, coal transportation, natural gas for generation and nuclear) and purchased power costs, net of off-system revenues, including MISO costs and revenues, above or below the amount set in base rates.
FASB - Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States.
FERC - The Federal Energy Regulatory Commission, a U.S. government agency.
FIN - FASB Interpretation. A FIN statement is an explanation intended to clarify accounting pronouncements previously issued by the FASB.
Fitch - Fitch Ratings, a credit rating agency.
5
Form 10-K - The combined Annual Report on Form 10-K for the year ended December 31, 2008, filed by the Ameren Companies with the SEC.
FSP - FASB Staff Position, a publication that provides application guidance on FASB literature.
FTRs - Financial transmission rights, financial instruments that entitle the holder to pay or receive compensation for certain congestion-related transmission charges between two designated points.
GAAP - Generally accepted accounting principles in the United States of America.
Genco - Ameren Energy Generating Company, a Resources Company subsidiary that operates a non-rate-regulated electric generation business in Illinois and Missouri.
Gigawatthour - One thousand megawatthours.
Heating degree-days - The summation of negative differences between the mean daily temperature and a 65- degree Fahrenheit base. This statistic is useful as an indicator of demand for electricity and natural gas for winter space heating for residential and commercial customers.
ICC - Illinois Commerce Commission, a state agency that regulates Illinois utility businesses, including the rate-regulated operations of CIPS, CILCO and IP.
Illinois Customer Choice Law - Illinois Electric Service Customer Choice and Rate Relief Law of 1997, which provided for electric utility restructuring and was designed to introduce competition into the retail supply of electric energy in Illinois.
Illinois electric settlement agreement - A comprehensive settlement of issues in Illinois arising out of the end of ten years of frozen electric rates, effective January 2, 2007. The Illinois electric settlement agreement, which became effective on August 28, 2007, was designed to avoid new rate rollback and freeze legislation and legislation that would impose a tax on electric generation in Illinois. The settlement addresses the issue of power procurement, and it includes a comprehensive rate relief and customer assistance program.
Illinois EPA - Illinois Environmental Protection Agency, a state government agency.
Illinois Regulated - A financial reporting segment consisting of the regulated electric and natural gas transmission and distribution businesses of CIPS, CILCO, IP and AITC.
IP - Illinois Power Company, an Ameren Corporation subsidiary. IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenIP.
IP LLC - Illinois Power Securitization Limited Liability Company, which was a special-purpose Delaware limited-liability company. It was dissolved in February 2009 because the remaining TFNs, with respect to which this entity was created, were redeemed by IP in September 2008.
IP SPT - Illinois Power Special Purpose Trust, which was created as a subsidiary of IP LLC to issue TFNs as allowed under the Illinois Customer Choice Law. It was dissolved in February 2009 because the remaining TFNs were redeemed by IP in September 2008.
IPA - Illinois Power Agency, a state government agency that has broad authority to assist in the procurement of electric power for residential and nonresidential customers beginning in June 2009.
Kilowatthour - A measure of electricity consumption equivalent to the use of 1,000 watts of power over a period of one hour.
Lehman - Lehman Brothers Holdings, Inc.
MACT - Maximum Achievable Control Technology.
Marketing Company - Ameren Energy Marketing Company, a Resources Company subsidiary that markets power for Genco, AERG and EEI.
Medina Valley - AmerenEnergy Medina Valley Cogen L.L.C., a Resources Company subsidiary, which owns a 40-megawatt gas-fired electric generation plant.
Megawatthour - One thousand kilowatthours.
MGP - Manufactured gas plant.
MISO - Midwest Independent Transmission System Operator, Inc.
MISO Day Two Energy Market - A market that uses market-based pricing, incorporating transmission congestion and line losses, to compensate market participants for power.
Missouri Regulated - A financial reporting segment consisting of UE’s rate-regulated businesses.
Mmbtu - One million Btus.
Money pool - Borrowing agreements among Ameren and its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools maintained for rate-regulated and non-rate-regulated business are referred to as the utility money pool and the non-state-regulated subsidiary money pool, respectively.
Moody’s - Moody’s Investors Service Inc., a credit rating agency.
MoPSC - Missouri Public Service Commission, a state agency that regulates Missouri utility businesses, including the rate-regulated operations of UE.
MPS - Multi-Pollutant Standard, an agreement reached in 2006 among Genco, CILCO (AERG), EEI and the Illinois EPA, which was codified in Illinois environmental regulations.
MTM - Mark-to-market.
MW - Megawatt.
Native load - Wholesale customers and end-use retail customers, whom we are obligated to serve by statute, franchise, contract, or other regulatory requirement.
Non-rate-regulated Generation - A financial reporting segment consisting of the operations or activities of Genco, the CILCORP parent company, AERG, EEI, Medina Valley, and Marketing Company.
NOx - Nitrogen oxide.
Noranda - Noranda Aluminum, Inc.
NPNS - Normal purchases and normal sales.
NRC- - Nuclear Regulatory Commission, a U.S. government agency.
NYMEX - New York Mercantile Exchange.
OATT - Open Access Transmission Tariff.
6
OCI - Other comprehensive income (loss) as defined by GAAP.
Off-system revenues - Revenues from other than native load sales.
OTC - Over-the-counter.
PGA - Purchased Gas Adjustment tariffs, which allow the passing through of the actual cost of natural gas to utility customers.
PJM - PJM Interconnection LLC.
PUHCA 2005 - The Public Utility Holding Company Act of 2005, enacted as part of the Energy Policy Act of 2005, effective February 8, 2006.
Regulatory lag - Adjustments to retail electric and natural gas rates are based on historic cost levels. Rate increase requests can take up to 11 months to be acted upon by the MoPSC and the ICC. As a result, revenue increases authorized by regulators will lag behind changing costs.
Resources Company - Ameren Energy Resources Company, LLC, an Ameren Corporation subsidiary that consists of non-rate-regulated operations, including Genco, Marketing Company, EEI, AFS, and Medina Valley. It is the successor to Ameren Energy Resources Company, which was eliminated in an internal reorganization in February 2008.
RFP - Request for proposal.
RTO - Regional Transmission Organization.
S&P - Standard & Poor’s Ratings Services, a credit rating agency that is a division of The McGraw-Hill Companies, Inc.
SEC - Securities and Exchange Commission, a U.S. government agency.
SFAS - Statement of Financial Accounting Standards, the accounting and financial reporting rules issued by the FASB.
SO2 - Sulfur dioxide.
TFN - Transitional Funding Trust Notes issued by IP SPT as allowed under the Illinois Customer Choice Law. IP designated a portion of cash received from customer billings to pay the TFNs. The designated funds received by IP were remitted to IP SPT. The designated funds were restricted for the sole purpose of making payments of principal and interest on, and paying other fees and expenses related to, the TFNs. Since the application of FIN 46R, IP did not consolidate IP SPT. Therefore, the obligation to IP SPT appears on IP’s balance sheet as of December 31, 2007. In September 2008, IP redeemed the remaining TFNs.
TVA - Tennessee Valley Authority, a public power authority.
UE - Union Electric Company, an Ameren Corporation subsidiary that operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri as AmerenUE.
FORWARD-LOOKING STATEMENTS
Statements in this report not based on historical facts are considered “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 under Risk Factors and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:
regulatory or legislative actions, including changes in regulatory policies and ratemaking determinations and future rate proceedings or future legislative actions that seek to limit or reverse rate increases;
uncertainty as to the continued effectiveness of the Illinois power procurement process;
changes in laws and other governmental actions, including monetary and fiscal policies;
changes in laws or regulations that adversely affect the ability of electric distribution companies and other purchasers of wholesale electricity to pay their suppliers, including UE and Marketing Company;
enactment of legislation taxing electric generators, in Illinois or elsewhere;
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, and the implementation of deregulation, such as occurred when the electric rate freeze and power supply contracts expired in Illinois at the end of 2006;
increasing capital expenditure and operating expense requirements and our ability to recover these costs in a timely fashion in light of regulatory lag;
the effects of participation in the MISO;
the cost and availability of fuel such as coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of purchased power and natural gas for distribution; and the level and volatility of future market prices for such commodities, including the ability to recover the costs for such commodities;
the effectiveness of our risk management strategies and the use of financial and derivative instruments;
prices for power in the Midwest, including forward prices;
business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products;
disruptions of the capital markets or other events that make the Ameren Companies’ access to necessary capital, including short-term credit and liquidity, impossible, more difficult or more costly;
7
our assessment of our liquidity;
the impact of the adoption of new accounting standards and the application of appropriate technical accounting rules and guidance;
actions of credit rating agencies and the effects of such actions;
weather conditions and other natural phenomena, including impacts to our customers;
the impact of system outages caused by severe weather conditions or other events;
generation plant construction, installation and performance, including costs associated with UE’s Taum Sauk pumped-storage hydroelectric plant incident and the plant’s future operation;
impairments of long-lived assets or goodwill;
recoverability through insurance of costs associated with UE’s Taum Sauk pumped-storage hydroelectric plant incident;
operation of UE’s nuclear power facility, including planned and unplanned outages, and decommissioning costs;
the effects of strategic initiatives, including acquisitions and divestitures;
the impact of current environmental regulations on utilities and power generating companies and the expectation that more stringent requirements, including those related to greenhouse gases, will be enacted over time, which could have a negative financial effect;
labor disputes, future wage and employee benefits costs, including changes in discount rates and returns on benefit plan assets;
the inability of our counterparties and affiliates to meet their obligations with respect to contracts, credit facilities and financial instruments;
the cost and availability of transmission capacity for the energy generated by the Ameren Companies’ facilities or required to satisfy energy sales made by the Ameren Companies;
legal and administrative proceedings; and
acts of sabotage, war, terrorism or intentionally disruptive acts.
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 update or revise publicly any forward-looking statements to reflect new information or future events.
8
PART I. FINANCIAL INFORMATION
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions, except per share amounts)
Operating Revenues:
Electric
Gas
Total operating revenues
Operating Expenses:
Fuel
Purchased power
Gas purchased for resale
Other operations and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Operating Income
Other Income and Expenses:
Miscellaneous income
Miscellaneous expense
Total other income
Interest Charges
Income Before Income Taxes
Income Taxes
Net Income
Less: Net Income Attributable to Noncontrolling Interests
Net Income Attributable to Ameren Corporation
Earnings per Common Share – Basic and Diluted
Dividends per Common Share
Average Common Shares Outstanding
The accompanying notes are an integral part of these consolidated financial statements.
9
CONSOLIDATED BALANCE SHEET
ASSETS
Current Assets:
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $40 and $28, respectively)
Unbilled revenue
Miscellaneous accounts and notes receivable
Materials and supplies
Mark-to-market derivative assets
Current portion of regulatory assets
Other current assets
Total current assets
Property and Plant, Net
Investments and Other Assets:
Nuclear decommissioning trust fund
Goodwill
Intangible assets
Regulatory assets
Other assets
Total investments and other assets
TOTAL ASSETS
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt
Short-term debt
Accounts and wages payable
Taxes accrued
Interest accrued
Mark-to-market derivative liabilities
Other current liabilities
Total current liabilities
Long-term Debt, Net
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net
Accumulated deferred investment tax credits
Regulatory liabilities
Asset retirement obligations
Pension and other postretirement benefits
Other deferred credits and liabilities
Total deferred credits and other liabilities
Commitments and Contingencies (Notes 2, 8, 9 and 10)
Ameren Corporation Stockholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 213.4 and 212.3, respectively
Other paid-in capital, principally premium on common stock
Retained earnings
Accumulated other comprehensive income
Total Ameren Corporation stockholders’ equity
Noncontrolling Interests
Total equity
TOTAL LIABILITIES AND EQUITY
10
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sales of emission allowances
Net mark-to-market gain on derivatives
Amortization of nuclear fuel
Amortization of debt issuance costs and premium/discounts
Deferred income taxes and investment tax credits, net
Other
Changes in assets and liabilities:
Receivables
Taxes accrued, net
Assets, other
Liabilities, other
Counterparty collateral, net
Taum Sauk costs, net of insurance recoveries
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Nuclear fuel expenditures
Purchases of securities – nuclear decommissioning trust fund
Sales of securities – nuclear decommissioning trust fund
Purchases of emission allowances
Net cash used in investing activities
Cash Flows From Financing Activities:
Dividends on common stock
Capital issuance costs
Dividends paid to noncontrolling interest holders
Short-term debt, net
Redemptions, repurchases, and maturities of long-term debt
Issuances:
Common stock
Long-term debt
Net cash provided by financing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of period
11
UNION ELECTRIC COMPANY
STATEMENT OF INCOME
Electric – excluding off-system
Electric – off-system
Income Before Income Taxes and Equity in Income of Unconsolidated Investment
Income Before Equity in Income of Unconsolidated Investment
Equity in Income of Unconsolidated Investment, Net of Taxes
Preferred Stock Dividends
Net Income Available to Common Stockholder
The accompanying notes as they relate to UE are an integral part of these financial statements.
12
BALANCE SHEET
Accounts receivable – trade (less allowance for doubtful accounts of $10 and $8, respectively)
Accounts receivable – affiliates
LIABILITIES AND STOCKHOLDERS’ EQUITY
Intercompany note payable – Ameren
Accounts payable – affiliates
Current portion of regulatory liabilities
Stockholders’ Equity:
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding
Preferred stock not subject to mandatory redemption
Total stockholders’ equity
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
13
STATEMENT OF CASH FLOWS
Net cash used in operating activities
Money pool advances, net
Dividends on preferred stock
Intercompany note payable – Ameren, net
Issuances of long-term debt
14
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
15
Accounts receivable – trade (less allowance for doubtful accounts of $7 and $6, respectively)
Current portion of intercompany note receivable – Genco
Current portion of intercompany tax receivable – Genco
Counterparty collateral asset
Intercompany note receivable – Genco
Intercompany tax receivable – Genco
Borrowings from money pool
Customer deposits
Mark-to-market derivative liabilities – affiliates
Commitments and Contingencies (Notes 2, 8, and 9)
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding
Other paid-in capital
16
Money pool borrowings, net
Net cash used in financing activities
17
AMEREN ENERGY GENERATING COMPANY
Operating Revenues
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
18
Intangible Assets
Other Assets
LIABILITIES AND STOCKHOLDER’S EQUITY
Current portion of intercompany note payable – CIPS
Current portion of intercompany tax payable – CIPS
Intercompany Note Payable – CIPS
Intercompany tax payable – CIPS
Commitments and Contingencies (Notes 2, 8 and 9)
Stockholder’s Equity:
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding
Accumulated other comprehensive loss
Total stockholder’s equity
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
19
Net mark-to-market (gain) loss on derivatives
20
CILCORP INC.
Goodwill impairment loss
Operating Income (Loss)
Miscellaneous Expenses
Income (Loss) Before Income Taxes
Net Income (Loss)
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
21
(Unaudited) (In millions, except shares)
Accounts receivable – trade (less allowance for doubtful accounts of $7 and $3, respectively)
Accounts and notes receivable – affiliates
Advances to money pool
Current portion of accumulated deferred income taxes, net
Subordinated borrowings – Ameren
CILCORP Inc. Stockholder’s Equity:
Common stock, no par value, 10,000 shares authorized – 1,000 shares outstanding
Retained earnings (deficit)
Total CILCORP Inc. stockholder’s equity
Noncontrolling Interest
22
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss on goodwill impairment
Pension and postretirement benefits
Subordinated borrowings – Ameren, net
Capital contribution from parent
23
CENTRAL ILLINOIS LIGHT COMPANY
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
24
Common stock, no par value, 20.0 shares authorized – 13.6 shares outstanding
25
26
ILLINOIS POWER COMPANY
Amortization of regulatory assets
The accompanying notes as they relate to IP are an integral part of these financial statements.
27
Accounts receivable – trade (less allowance for doubtful accounts of $15 and $12, respectively)
Common stock, no par value, 100.0 shares authorized – 23.0 shares outstanding
Other paid-in-capital
28
Deferred income taxes
IP SPT maturities
Overfunding of TFNs
Net cash provided by (used in) financing activities
29
AMEREN CORPORATION (Consolidated)
AMEREN ENERGY GENERATING COMPANY (Consolidated)
CILCORP INC. (Consolidated)
CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)
COMBINED NOTES TO FINANCIAL STATEMENTS
(Unaudited)
March 31, 2009
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and non-rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren and CILCORP holding companies depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report.
UE, or Union Electric Company, also known as AmerenUE, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.
CIPS, or Central Illinois Public Service Company, also known as AmerenCIPS, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
Genco, or Ameren Energy Generating Company, operates a non-rate-regulated electric generation business in Illinois and Missouri.
CILCO, or Central Illinois Light Company, also known as AmerenCILCO, is a subsidiary of CILCORP (a holding company). It operates a rate-regulated electric transmission and distribution business, a non-rate-regulated electric generation business (through its subsidiary, AERG) and a rate-regulated natural gas transmission and distribution business in Illinois.
IP, or Illinois Power Company, also known as AmerenIP, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
Ameren has various other subsidiaries responsible for the short- and long-term marketing of power, procurement of fuel, management of commodity risks, and provision of other shared services. Ameren has an 80% ownership interest in EEI, which until February 29, 2008, was held 40% by UE and 40% by Development Company. Ameren consolidates EEI for financial reporting purposes. UE reported EEI under the equity method until February 29, 2008. Effective February 29, 2008, UE’s and Development Company’s ownership interests in EEI were transferred to Resources Company through an internal reorganization. UE’s interest in EEI was transferred at book value indirectly through a dividend to Ameren.
The financial statements of Ameren, Genco, CILCORP and CILCO are prepared on a consolidated basis. UE, CIPS and IP have no subsidiaries and therefore their financial statements were not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. 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, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.
Earnings Per Share
There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three months ended March 31, 2009 and 2008. The number of stock options, restricted stock shares, and performance share units outstanding was immaterial.
30
Long-term Incentive Plan of 1998 and 2006 Omnibus Incentive Compensation Plan
A summary of nonvested shares as of March 31, 2009, under the Long-term Incentive Plan of 1998, as amended, and the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:
Nonvested at January 1, 2009
Granted(a)
Dividends
Forfeitures
Vested(b)
Nonvested at March 31, 2009
The fair value of each share unit awarded in March 2009 under the 2006 Plan was determined to be $15.52 based on Ameren’s closing common share price of $22.20 per share at March 2, 2009, and lattice simulations used to estimate expected share payout based on Ameren’s total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2009. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.24%, volatility of 21.3% to 33.1% for the peer group, and Ameren’s attainment of earnings per share of at least $2.54 during each year of the performance period.
Ameren recorded compensation expense of $5 million and $7 million for the quarters ended March 31, 2009 and 2008, respectively, and a related tax benefit of $2 million and $3 million for the quarters ended March 31, 2009 and 2008, respectively. As of March 31, 2009, total compensation cost of $19 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 23 months.
Accounting Changes and Other Matters
SFAS No. 157, Fair Value Measurements
In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value, and expands required disclosures about fair value measurements. See Note 7 - Fair Value Measurements for additional information on our adoption of SFAS No. 157.
SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51
In December 2007, the FASB issued SFAS No. 160, which establishes accounting and reporting standards for minority interests, which will be recharacterized as noncontrolling interests. Under the provisions of SFAS No. 160, noncontrolling interests will be classified as a component of equity separate from the parent’s equity; purchases or sales of equity interests that do not result in a change in control will be accounted for as equity transactions; net income attributable to the noncontrolling interest will be included in consolidated net income in the statement of income; and upon a loss of control, the interest sold, as well as any interest retained, will be recorded at fair value, with any gain or loss recognized in earnings. We adopted SFAS No. 160 as of the beginning of 2009. SFAS No. 160 applies prospectively, except for the presentation and disclosure requirements, for which it applies retroactively. This standard is applicable to Ameren and CILCORP. See Noncontrolling Interest below for additional information.
SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities - an amendment of SFAS No. 133
In March 2008, the FASB issued SFAS No. 161, which requires enhanced disclosures about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and its related interpretations, and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS No. 161 was effective in the first quarter of 2009. The adoption of SFAS No. 161 did not have a material impact on our results of operations, financial position, or liquidity, because it provided enhanced disclosure requirements only. See Note 6 - Derivative Financial Instruments for additional information on our adoption of SFAS No. 161.
31
FSP SFAS No. 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies
In April 2009, the FASB issued FSP SFAS No. 141(R)-1, which amended the provisions related to the initial recognition and measurement, subsequent measurement and disclosure of assets and liabilities arising from contingencies in a business combination under SFAS No.141(R), “Business Combinations.” FSP SFAS No. 141(R)-1 was effective as of January 1, 2009. It applies prospectively to business combinations completed on or after that date.
FSP SFAS No. 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly
In April 2009, the FASB issued FSP SFAS No. 157-4, which will be effective for us as of June 30, 2009. FSP SFAS No. 157-4 provides additional guidance regarding the factors that should be considered in estimating fair value when there has been a significant decrease in market activity for an asset or liability. The guidance, which applies to all fair value measurements, does not change the objective of a fair value measurement. The adoption of FSP SFAS No. 157-4 is not expected to have a material impact on our results of operations, financial condition, or liquidity.
FSP SFAS No. 107-1 and APB Opinion No. 28-1, Interim Disclosures about Fair Value of Financial Instruments
In April 2009, the FASB issued FSP SFAS No. 107-1 and APB Opinion No. 28-1, which will be effective for us as of June 30, 2009. It amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” and APB Opinion No. 28, “Interim Financial Reporting,” to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. The adoption of FSP SFAS No. 107-1 and APB Opinion No. 28-1 will not have a material impact on our results of operations, financial position, or liquidity, because it provides enhanced disclosure requirements only.
FSP SFAS No. 115-2 and SFAS No. 124-2, Recognition and Presentation of Other-Than-Temporary Impairments
In April 2009, the FASB issued FSP SFAS No. 115-2 and SFAS No. 124-2, which establishes a new method of recognizing and reporting other-than-temporary impairments of debt securities and contains additional annual and interim disclosure requirements related to debt and equity securities. Under the FSP, an impairment of debt securities is other-than-temporary if (1) the entity intends to sell the security, (2) it is more likely than not that the entity will be required to sell the security before recovery of its amortized cost basis, or (3) the entity does not expect to recover the security’s entire amortized cost basis. FSP SFAS No. 115-2 and SFAS No. 124-2 will be effective for us as of June 30, 2009. The adoption of FSP SFAS No. 115-2 and SFAS No. 124-2 is not expected to have a material impact on our results of operations, financial condition, or liquidity.
Goodwill and Intangible Assets
Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. Ameren’s and IP’s goodwill relates to the acquisition of IP in 2004. Ameren’s and CILCORP’s goodwill relates to the acquisition of CILCORP in 2003. Ameren’s goodwill also includes an additional 20% ownership interest in EEI acquired in 2004 as well as the acquisition of Medina Valley in 2003. During the first quarter of 2009, CILCORP recognized a goodwill impairment loss of $462 million. Ameren and IP did not recognize a goodwill impairment in the first quarter of 2009. See Note 14 - Goodwill Impairment for further information about CILCORP’s goodwill impairment.
Intangible Assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired. Ameren’s, UE’s, Genco’s, CILCORP’s and CILCO’s intangible assets consisted of emission allowances at March 31, 2009. See also Note 9 - Commitments and Contingencies for additional information on emission allowances.
32
The following table presents the SO2 and NOx emission allowances held and the related aggregate SO2 and NOx emission allowance book values that were carried as intangible assets as of March 31, 2009. Emission allowances consist of various individual emission allowance certificates and do not have expiration dates. Emission allowances are charged to fuel expense as they are used in operations.
Ameren(d)
UE
Genco
CILCORP(f)
CILCO (AERG)
EEI
(c)
The book value represents SO2 and NOx emission allowances for use in periods through 2038. The book value at December 31, 2008, for Ameren, UE, Genco, CILCORP, CILCO (AERG), and EEI was $167 million, $48 million, $49 million, $35 million, $1 million, and $9 million, respectively.
The following table presents the amortization expense based on usage of emission allowances, net of gains from emission allowance sales, for Ameren, UE, Genco, CILCORP and CILCO (AERG) during the three months ended March 31, 2009 and 2008.
Ameren(a)(b)
CILCORP(b)
Excise Taxes
Excise taxes imposed on us are reflected on Missouri electric, Missouri gas, and Illinois gas customer bills. They are recorded gross in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes on the statement of income. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued on the balance sheet. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes for the three months ended March 31, 2009 and 2008:
Ameren
CIPS
CILCORP
CILCO
IP
Uncertain Tax Positions
The amount of unrecognized tax benefits as of March 31, 2009, was $129 million, $25 million, less than $1 million, $55 million, $31 million, $31 million and less than $1 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. The total unrecognized tax benefits (detriments), that would impact the effective tax rate, if recognized, for each of the respective companies was as follows: Ameren - $11 million, UE - $1 million, CIPS - none, Genco - ($2 million), CILCORP - less than $1 million, CILCO - less than $1 million, and IP - none.
Ameren is currently under U.S. federal income tax examination for years 2005, 2006 and 2007. State income tax returns are generally subject to examination for a period of three years after filing of the return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. The Ameren Companies do not have material state income tax issues under examination, administrative appeals, or litigation.
It is reasonably possible that events will occur during the next 12 months that would cause the total amount of unrecognized tax
33
benefits to increase or decrease. However, the Ameren Companies do not believe such increases or decreases would be material to their financial condition or results of operations.
Asset Retirement Obligations
AROs at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP increased compared to December 31, 2008, to reflect the accretion of obligations to their fair values.
At Ameren, noncontrolling interest comprises the 20% of EEI’s net assets that are not owned by Ameren and the preferred stock not subject to mandatory redemption of the Ameren subsidiaries. These noncontrolling interests are classified as a component of equity separate from Ameren’s equity in Ameren’s consolidated balance sheet. At CILCORP, noncontrolling interest comprises the preferred stock not subject to mandatory redemption of its subsidiary, CILCO. This noncontrolling interest is classified as a component of equity separate from CILCORP’s equity in CILCORP’s consolidated balance sheet. Equity changes attributable to the noncontrolling interest at Ameren included net income of $4 million and $11 million and dividends paid to the noncontrolling interest holders of $8 million and $10 million for the three months ended March 31, 2009, and 2008, respectively. CILCORP had no changes in equity attributable to the noncontrolling interest for the three months ended March 31, 2009.
NOTE 2 - RATE AND REGULATORY MATTERS
Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.
Missouri
2009 Electric Rate Order
In January 2009, the MoPSC issued an order approving an increase for UE in annual revenues for electric service and the implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism, among other things. In February 2009, Noranda and the Missouri Office of Public Counsel appealed certain aspects of the MoPSC decision to the Circuit Court of Pemiscot County, Missouri, the Circuit Court of Stoddard County, Missouri, and the Circuit Court of Cole County, Missouri. UE cannot predict the outcome of the court appeals.
Environmental Cost Recovery Mechanism
A Missouri law enacted in July 2005 enables the MoPSC to put in place an environmental cost recovery mechanism for Missouri’s utilities. The MoPSC initiated a proceeding in December 2008 to develop revised rules for the cost recovery mechanism. Rules for the environmental cost recovery mechanism were approved by the MoPSC in April 2009 and will be effective once published in the Missouri Register. UE will not be able to implement an environmental cost recovery mechanism until so authorized by the MoPSC as part of a rate case proceeding.
Illinois
Illinois Electric Settlement Agreement
In 2007, key stakeholders in Illinois agreed to avoid rate rollback and freeze legislation that would impose a tax on electric generation. These stakeholders wanted to address the increase in electric rates and the future power procurement process in Illinois. The terms of the agreement included a comprehensive rate relief and customer assistance program.
The Ameren Illinois Utilities, Genco, and CILCO (AERG) recognize in their financial statements the costs of their respective rate relief contributions and program funding in a manner corresponding with the timing of the funding. Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues, during the quarter ended March 31, 2009, of $6 million, $1 million, less than $1 million, $1 million, $2 million, and $1 million, respectively (quarter ended March 31, 2008 - $11 million, $2 million, $1 million, $2 million, $4 million, and $2 million, respectively) under the terms of the Illinois electric settlement agreement.
Power Procurement Plan
As part of the Illinois electric settlement agreement, the reverse auction used for power procurement in Illinois was discontinued. It was replaced with a new power procurement process led by the IPA, which was established as a part of the Illinois electric settlement agreement, beginning in 2009. In January 2009, the ICC approved the electric power procurement plan filed by the IPA for both the Ameren Illinois Utilities and Commonwealth Edison Company. The plan outlined the wholesale products that the IPA will procure on behalf of the Ameren Illinois Utilities for the period June 1, 2009, through May 30, 2014. The IPA procured capacity through a RFP process on behalf of the Ameren Illinois Utilities in April 2009. See Note 9 - Commitments and Contingencies for further information about the results of the capacity RFP. The energy swaps and renewable energy credits are expected to be procured through a RFP process during the second quarter of 2009.
34
ICC Reliability Audit
In August 2007, the ICC retained Liberty Consulting Group to investigate, analyze, and report to the ICC on the Ameren Illinois Utilities’ transmission and distribution systems and reliability following the July 2006 wind storms and a November 2006 ice storm. In October 2008, Liberty Consulting Group presented the ICC with a final report containing recommendations for the Ameren Illinois Utilities to improve their systems and their response to emergencies. The ICC directed the Ameren Illinois Utilities to present to the ICC a plan to implement Liberty Consulting Group’s recommendations. The plan was submitted to the ICC in November 2008. Liberty Consulting Group will monitor the Ameren Illinois Utilities’ efforts to implement the recommendations and any initiatives that the Ameren Illinois Utilities undertake. The Ameren Illinois Utilities expect to incur $20 million of capital costs and an estimated $60 million of cumulative operations and maintenance expenses for the 2009 through 2013 timeframe in order to implement the recommendations. The Ameren Illinois Utilities will seek recovery of these costs in future rate cases.
Federal
Nuclear Combined Construction and Operating License Application
In July 2008, UE filed an application with the NRC for a combined construction and operating license for a potential new 1,600-megawatt nuclear unit at UE’s existing Callaway County, Missouri, nuclear plant site. Pursuant to the DOE’s procedures, in 2008 UE filed with the DOE Part I and Part II of its application for a loan guarantee to support the potential construction of a new nuclear unit. UE has also signed contracts for COLA services and certain long lead-time nuclear-unit related equipment (heavy forgings). The filing of the COLA and the DOE loan guarantee application and entering into these contracts did not mean a decision had been made to build a new nuclear unit. These were only the first steps in the regulatory licensing and procurement process. They were necessary actions to preserve the option to develop a new nuclear unit to supply power to UE’s customers.
In early 2009, the Missouri Clean and Renewable Energy Construction Act was separately introduced in both the Missouri Senate and House of Representatives. These bills were designed to allow the MoPSC to authorize, among other things, utilities to recover the costs of financing and tax payments associated with a new generating plant while that plant is being constructed. Recovery of actual construction costs still could not have begun until a plant was put into service. UE believes legislation allowing timely recovery of financing costs during construction must be enacted in order for it to build a new nuclear unit to meet its baseload generation capacity needs. However, passage of this or other legislation was not a commitment or guarantee that UE would build a new nuclear unit.
On April 23, 2009, senior management of UE announced that they had asked the legislative sponsors of the Missouri Clean and Renewable Energy Construction Act to withdraw the bills from consideration by the Missouri General Assembly. UE believed pursuing the legislation being considered in the Missouri Senate in its current form would not give it the financial and regulatory certainty needed to complete the project. As a result, UE announced that it was suspending its efforts to build a new nuclear unit at its existing Missouri nuclear plant site. UE will consider all available and feasible generation options to meet future customer requirements as part of an integrated resource plan that UE is due to file with the MoPSC in June 2010.
As of March 31, 2009, UE has capitalized approximately $75 million as construction work in progress related to the COLA and heavy forgings. In addition, UE has remaining contractual commitments of approximately $85 million for the forgings. The incurred costs will remain capitalized while management assesses all options to maximize the value of its investment in this project. However, UE cannot at this time predict which option will ultimately be selected, whether any or all of its investment in this project will be realized or whether there will be a material impact on UE’s and Ameren’s results of operations. If all efforts are permanently abandoned with respect to the future construction of a new nuclear unit in Missouri, it is possible that a charge to earnings could be recognized in a future period.
FERC Order - MISO Charges
In May 2007, UE, CIPS, CILCO and IP filed with the U.S. Court of Appeals for the District of Columbia Circuit an appeal of FERC’s March 2007 order involving the reallocation of certain MISO operational costs among MISO participants retroactive to 2005. In August 2007, the court granted FERC’s motion to hold the appeal in abeyance until the end of the continuing proceedings at FERC regarding these costs. Other MISO participants also filed appeals. On August 10, 2007, UE, CIPS, CILCO, and IP filed a complaint with FERC regarding the MISO tariff’s allocation methodology for these same MISO operational charges. In November 2007, FERC issued two orders relative to these allocation matters. One of these orders addressed requests for rehearing of prior orders in the proceedings, and one concerned MISO’s compliance with FERC’s orders to date in the proceedings. In December 2007, UE, CIPS, CILCO and IP requested FERC’s clarification or rehearing of its November 2007 order regarding MISO’s compliance with FERC’s orders. UE, CIPS, CILCO, and IP maintained that MISO was required to reallocate certain of MISO’s operational costs among MISO market participants, which would result in refunds to UE, CIPS, CILCO, and IP retroactive to April 2006. On November 7, 2008, FERC granted the request for clarification and directed MISO to reallocate certain costs and provide refunds as requested for the period April 2006 to August 2007. On November 10, 2008, FERC granted relief requested in the complaints filed by UE, CIPS, CILCO, IP and others regarding further reallocation for these same MISO operational charges and directed MISO to calculate refunds for the period from August 10, 2007, forward.
Several parties to these proceedings protested MISO’s proposed implementation of these refunds, requested rehearing of FERC’s orders and, in some cases, have appealed FERC’s orders to the courts. In March 2009, MISO began resettling its markets to provide refunds as FERC directed effective on August 10, 2007. On May 6, 2009, FERC issued an order that upheld most of the conclusions of their November 10, 2008, order but changed the effective date for refunds such that certain operational costs will be allocated among MISO market participants beginning November 10, 2008, instead of August 10, 2007. The Ameren Companies continue to evaluate this order, but do not believe it will have a material effect on their results of operations, financial position, or liquidity. FERC has not yet ruled on rehearing requests related to its November 7, 2008, order.
NOTE 3 - SHORT-TERM BORROWINGS AND LIQUIDITY
The liquidity needs of the Ameren Companies are typically supported through the use of available cash and drawings under committed bank credit facilities.
35
At March 31, 2009, Ameren and certain of its subsidiaries had $2.15 billion of committed credit facilities, consisting of three facilities, in the amounts of $1.15 billion, $500 million and $500 million maturing in July 2010, January 2010, and January 2010, respectively. The following table summarizes the borrowing activity and relevant interest rates as of March 31, 2009, under the $1.15 billion credit facility (excluding letters of credit issued under this facility) and the 2007 and 2006 $500 million credit facilities:
(Parent)
March 31, 2009:
Average daily borrowings outstanding during 2009
Outstanding short-term debt at period end
Weighted-average interest rate during 2009
Peak short-term borrowings during 2009(a)
Peak interest rate during 2009
Based on outstanding borrowings under the $1.15 billion credit facility and the 2007 and 2006 $500 million credit facilities (including reductions for $11 million of letters of credit issued under the $1.15 billion credit facility and unfunded Lehman participations under the $1.15 billion credit facility and the 2006 $500 million credit facility), the available amounts under the facilities at March 31, 2009, were $492 million, $500 million, and $378 million, respectively.
On June 25, 2008, Ameren entered into a $300 million term loan agreement due June 24, 2009, which was fully drawn on June 26, 2008. The average annual interest rate for borrowing under the $300 million term loan agreement was 1.95% during the three months ended March 31, 2009.
On January 21, 2009, Ameren entered into a $20 million term loan agreement due January 20, 2010, which was fully drawn on January 21, 2009. The average annual interest rate for borrowing under the $20 million term loan agreement was 2.13% during the three months ended March 31, 2009.
Indebtedness Provisions and Other Covenants
The information below presents a summary of the Ameren Companies’ and AERG’s compliance with indebtedness provisions and other covenants. See Note 4 - Short-term Borrowings and Liquidity in the Form 10-K for a detailed description of those provisions.
The 2007 $500 million credit facility and 2006 $500 million credit facility limit the amount of CIPS, CILCORP, CILCO and IP common and preferred stock dividend payments to $10 million per year each if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have received a below investment-grade credit rating from either Moody’s or S&P. With respect to AERG, which currently is not rated by Moody’s or S&P, the common and preferred stock dividend restriction will not apply if its ratio of consolidated total debt to consolidated operating cash flow, pursuant to a calculation defined in the facilities, is less than or equal to 3.0 to 1.0. CILCORP’s senior unsecured long-term debt credit ratings from Moody’s and S&P are currently below investment-grade, causing it to be subject to this dividend payment limitation. As of March 31, 2009, AERG failed to meet the debt-to-operating-cash-flow ratio test in the 2007 and 2006 $500 million credit facilities. AERG’s ability to pay dividends is therefore currently limited to a maximum of $10 million per fiscal year. CIPS, CILCO and IP are not currently limited in their dividend payments by this provision of the 2007 or 2006 credit facilities. Ameren’s access to dividends from CILCO and AERG is currently limited by dividend restrictions at CILCORP.
The $300 million term loan agreement entered into in June 2008 has terms similar to the $1.15 billion credit facility discussed below, except that amounts repaid under the term loan agreement may not be reborrowed. Under the $20 million term loan agreement entered into in January 2009, Ameren may elect, for up to three 30-day periods, to pay down and reduce to zero the outstanding
36
principal balance. The term loan agreements require Ameren to maintain consolidated indebtedness of not more then 65% of consolidated total capitalization pursuant to a calculation defined in the term loan agreements.
The $1.15 billion credit facility, the 2007 $500 million credit facility, and the 2006 $500 million credit facility also limit the total indebtedness of each borrower to 65% of total consolidated capitalization pursuant to a calculation set forth in the facilities. As of March 31, 2009, the ratios of total indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the $1.15 billion credit facility, were 53%, 54% and 51%, for Ameren, UE and Genco, respectively. The ratios for CIPS, CILCORP, CILCO, IP and AERG, calculated in accordance with the provisions of the 2007 $500 million credit facility and 2006 $500 million credit facility, were 48%, 62%, 41%, 52% and 34%, respectively. The ratio of consolidated indebtedness to consolidated total capitalization for Ameren calculated in accordance with the provisions of the $300 million term loan agreement and the $20 million term loan agreement were 54% and 53%, respectively.
None of Ameren’s credit facilities or financing arrangements contain credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At March 31, 2009, management believes that the Ameren Companies and AERG were in compliance with their credit facilities and term loan agreement provisions and covenants.
Money Pools
Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements.
Utility
Through the utility money pool, the pool participants may access the committed credit facilities. See discussion above for amounts available under the facilities at March 31, 2009. CIPS, CILCO and IP borrow from each other through the utility money pool agreement subject to applicable regulatory short-term borrowing authorizations. Ameren and AERG may participate in the utility money pool only as lenders. The primary sources of external funds for the utility money pool are the 2006 $500 million and the 2007 $500 million credit facilities. The average interest rate for borrowing under the utility money pool for the three months ended March 31, 2009, was 0.24% (2008 - 4.1%).
Non-state-regulated Subsidiaries
Ameren Services, Resources Company, Genco, AERG, Marketing Company, AFS and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company authorization and applicable regulatory short-term borrowing authorizations, to access funding from Ameren’s $1.15 billion credit facility through a non-state-regulated subsidiary money pool agreement. See discussion above for amount available under the $1.15 billion credit facility at March 31, 2009. In addition, Ameren had available cash balances at March 31, 2009, which can be loaned into this arrangement. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three months ended March 31, 2009, was 1.2% (2008 - 4.4%).
See Note 8 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three months ended March 31, 2009.
In addition, in March 2009, CILCORP and AERG each entered into a separate unilateral borrowing agreement with Ameren and Ameren Services, which enables CILCORP and AERG to make short-term borrowings directly from Ameren. Borrowings under the unilateral borrowing agreements are subordinate to all other indebtedness. As of March 31, 2009, CILCORP and AERG had $146 million and $100 million, respectively, of short-term borrowings under the unilateral borrowing agreements with an average interest rate of 1.7% for each for the three months ended March 31, 2009. Ameren Services is responsible for operation and administration of the agreements.
NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS
Under DRPlus, pursuant to an effective SEC Form S-3 registration statement, and under our 401(k) plan, pursuant to an effective SEC Form S-8 registration statement, Ameren issued a total of 1.1 million new shares of common stock valued at $28 million in the three months ended March 31, 2009.
In March 2009, UE issued $350 million of 8.45% senior secured notes due March 15, 2039, with interest payable semiannually on March 15 and September 15 of each year, beginning in September 2009. These notes are secured by first mortgage bonds. UE received net proceeds of $346 million, which were used to repay short-term debt. In connection with this issuance of $350 million of senior secured notes, UE agreed, for so long as these senior secured notes are outstanding, that it will not, prior to maturity, cause a
37
first mortgage bond release date to occur. The first mortgage bond release date is the date at which the security provided by the pledge under UE’s first mortgage indenture would no longer be available to holders of any outstanding series of its senior secured notes and such indebtedness would become senior unsecured indebtedness.
In conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was increased to fair value by $111 million. Amortization related to fair-value adjustments was $1 million (2008 - $1 million) for the three months ended March 31, 2009, and was included in interest expense in the Consolidated Statements of Income of Ameren and CILCORP.
See Note 4 - Short-Term Borrowings and Liquidity under Part II, Item 8 of the Form 10-K regarding CILCORP’s pledge of the common stock of CILCO as security for its obligations under the 2007 $500 million credit facility and the 2006 $500 million credit facility.
In September 2008, CILCORP commenced a cash tender offer for any and all of its outstanding 8.70% senior notes due 2009 ($123.755 million aggregate principal amount) and its 9.375% senior bonds due 2029 ($210.565 million aggregate principal amount), collectively, the “notes.” Concurrent with the tender offer, CILCORP solicited consents from the holders of the notes to certain proposed amendments to the indenture governing these securities. Any holder tendering securities as part of this offer is deemed to consent to the proposed amendments. No consents will be accepted separate from a tender of such holder’s securities. The amendments would eliminate certain restrictive covenants in the indenture and the notes. In April 2009, CILCORP terminated the tender offer and the consent solicitation related to the outstanding 8.70% senior notes due 2009 and extended the tender offer and consent solicitation related to the 2029 bonds to July 31, 2009. The total consideration for each $1,000 principal amount of 2029 bonds validly tendered on or prior to the current consent and expiration date is $1,230, which includes a consent payment of $50 per $1,000 principal amount of such 2029 bonds tendered on or prior to such date. Holders validly tendering and not withdrawing the 2029 bonds on or before the extended consent and expiration date are eligible to receive the corresponding total consideration. In addition, tenders of 2029 bonds, including previously-tendered 2029 bonds, may be withdrawn (and related consents may be rescinded) at any time prior to July 31, 2009. As of April 29, 2009, CILCORP had received consents, net of those rescinded, from the holders of $206.7 million, or 98.2%, of its outstanding 2029 bonds. Consummation of the tender offer and the consent solicitation is subject to a number of conditions, including the absence of certain adverse legal and market developments, as described in the offer to purchase. CILCORP has reserved the right to amend, further extend, terminate, or waive any conditions to the tender offer and the consent solicitation at any time. The impact on CILCORP’s net income of the tender offer is expected to be immaterial, if consummated.
In March 2009, IP completed its offer to exchange up to $400 million of its unregistered 9.75% senior secured notes due November 15, 2018, for a like amount of registered 9.75% senior secured notes due November 15, 2018. The unregistered senior secured notes were issued and sold in October 2008 with registration rights in a private placement. The entire aggregate principal amount of unregistered notes was tendered for exchange and not withdrawn prior to the expiration of the exchange offer.
Indenture Provisions and Other Covenants
The information below presents a summary of the Ameren Companies’ compliance with indenture provisions and other covenants. See Note 5 - Long-term Debt and Equity Financings in the Form 10-K for a detailed description of those provisions.
UE’s, CIPS’, CILCO’s and IP’s indenture provisions and articles of incorporation include covenants and provisions related to the issuances of first mortgage bonds and preferred stock. UE, CIPS, CILCO and IP are required to meet certain ratios to issue first mortgage bonds and preferred stock. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable for the 12 months ended March 31, 2009, at an assumed interest and dividend rate of 8%.
38
UE’s mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by UE. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.7 billion of free and unrestricted retained earnings at March 31, 2009.
CILCO’s articles of incorporation contain certain provisions that prohibit the payment of dividends on its common stock (1) from either paid-in surplus or any surplus created by a reduction of stated capital or capital stock, or (2) if at the time of dividend declaration, there shall not remain to the credit of earned surplus account (after deducting the amount of such dividends) an amount at least equal to two times the annual dividend requirement on all outstanding shares of CILCO’s preferred stock.
Genco’s and CILCORP’s indentures include provisions that require the companies to maintain certain debt service coverage and/or debt-to-capital ratios in order for the companies to pay dividends, to make certain principal or interest payments, to make certain loans to or investments in affiliates, or to incur additional indebtedness. The following table summarizes these ratios for the 12 months ended March 31, 2009:
Required
Interest
CoverageRatio
Actual
InterestCoverageRatio
Debt-to-
CapitalRatio
Capital
Ratio
Genco (a)
CILCORP(c)
Genco’s debt incurrence-related ratio restrictions and restricted payment limitations under its indenture may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness. Even if CILCORP is not in compliance with these restrictions, CILCORP may still make payments of dividends or intercompany loans if its senior long-term debt rating is at least BB+ from S&P, Baa2 from Moody’s, and BBB from Fitch. At March 31, 2009, CILCORP’s senior long-term debt ratings from S&P, Moody’s and Fitch were BB+, Ba2, and BBB-, respectively. The common stock of CILCO is pledged as security to the holders of CILCORP’s senior notes and bonds and credit facility obligations.
In order for the Ameren Companies to issue securities in the future, they will have to comply with any applicable tests in effect at the time of any such issuances.
Off-Balance-Sheet Arrangements
At March 31, 2009, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.
39
NOTE 5 - OTHER INCOME AND EXPENSES
The following table presents Other Income and Expenses for each of the Ameren Companies for the three months ended March 31, 2009 and 2008:
Ameren:(a)
Miscellaneous income:
Interest and dividend income
Allowance for equity funds used during construction
Total miscellaneous income
Miscellaneous expense:
Total miscellaneous expense
UE:
CIPS:
CILCORP:
CILCO:
IP:
Interest income
NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity, and emission allowances. Price fluctuations in natural gas, fuel, and electricity may cause the following:
an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;
market values of fuel and natural gas inventories, emission allowances or purchased power that differ from the cost of those commodities in inventory; and
actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that
40
sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.
The following table presents open gross derivative volumes by commodity type as of March 31, 2009:
Coal (in tons)
Ameren(e)
CILCORP/CILCO
Gas (in mmbtu)
Heating oil (in gallons)
Power (in megawatthours)
SO2 Emission Allowances (in tons)
Contracts through 2009, 2012, 2011, and 2009 for gas, heating oil, power, and SO2 emission allowances, respectively.
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No. 133), requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 7 - Fair Value Measurements for our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our coal and purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at contract price upon physical delivery.
If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting under SFAS No. 133. We also consider whether gains and losses resulting from such derivatives qualify for deferral under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). Contracts that qualify for cash flow hedge accounting are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income.
Contracts that qualify for fair value hedge accounting are recorded at fair value, with changes in fair value charged or credited to the statement of income in the period in which the change occurs. In addition, the underlying exposure being hedged in a fair value hedge relationship is similarly treated. The net effect to the statement of income in a fair value hedge relationship is equal to the change in fair value of the derivative offset by the change in the value of the underlying.
Contracts that qualify for deferral under SFAS No. 71 are recorded at fair value, with changes in fair value charged or credited to regulatory assets or regulatory liabilities in the period in which the change occurs. Regulatory assets or regulatory liabilities are amortized to the statement of income as related losses and gains are reflected in rates charged to customers.
41
Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for the NPNS exception, hedge accounting under SFAS No. 133, or deferral accounting under SFAS No. 71. Such contracts are recorded at fair value with changes in the fair value charged or credited to the statement of income in the period in which the change occurs.
The following table presents the carrying value and balance sheet location of all derivative instruments as of March 31, 2009:
CILCORP/
Commodity contracts:
Power
MTM derivative assets
Total assets
Foreign exchange contracts
Other deferred credits and
liabilities
Total liabilities
Heating oil
MTM derivative liabilities
MTM derivative liabilities - affiliates
SO2 emission allowances
42
The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in accumulated OCI and regulatory assets or regulatory liabilities as of March 31, 2009:
Cumulative gains (losses) deferred in accumulated OCI:
Power forwards(b)
Interest rate swaps(c)(d)
Cumulative gains (losses) deferred in regulatory assets or liabilities:
Gas swaps and futures contracts(e)
Financial contracts(f)
Heating oil options and swaps(g)
Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. NYMEX-traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master trading and netting agreements, and daily exposure reporting to senior management.
We believe that entering into master trading and netting agreements mitigates the level of financial loss resulting from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) International Swaps and Derivatives Association agreement - a standardized financial gas and electric contract, (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association - a standardized contract for the purchase and sale of wholesale power, and (3) North American Energy Standards Board, Inc. agreement - a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.
Concentrations of Credit Risk
In determining our concentrations of credit risk related to derivative instruments, we reviewed our individual counterparties and categorized each counterparty into one of eight groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of March 31, 2009, if counterparty groups were to completely fail to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including NPNS contracts, which excludes collateral held and does not consider the legally binding right to net transactions based on master trading and netting agreements.
Coal
Producers
Utilities
Financial
Companies
Commodity
Marketing
Municipalities/
Cooperatives
Retail
Ameren(a)
43
The following table presents the amount of cash collateral held from counterparties, as of March 31, 2009, based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements:
The potential loss on counterparty exposures is reduced by all collateral held and the application of master trading and netting agreements. Collateral includes both cash collateral and other collateral held. Other collateral consisted of letters of credit in the amount of $43 million, $3 million, and $3 million held by Ameren, UE and Genco, respectively, as of March 31, 2009. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of March 31, 2009:
CommodityMarketing
Derivative Instruments with Credit Risk-Related Contingent Features
Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If we were to experience an adverse change in our credit ratings or a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of March 31, 2009, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral required to be posted with counterparties, based on the net liability position as allowed under the master trading and netting agreements, if the credit risk-related contingent features underlying these agreements were triggered on March 31, 2009, and those counterparties with rights to do so requested collateral:
Aggregate Fair Value of
Derivative Liabilities(a)
Cash
Collateral Posted
Ameren(c)
44
Cash Flow Hedges
The following table presents the pretax net gain (loss) for the three months ended March 31, 2009, associated with derivative instruments designated as cash flow hedges:
Derivatives in
SFAS No. 133
Cash Flow
Hedging
Relationship
Amount of
Gain (Loss)
Recognized in OCI
on Derivative(a)
Location of
Reclassified
from
Accumulated
OCI into
Income(b)
Reclassified from
Accumulated OCI
Into Income(b)
Location of Gain (Loss)
Recognized in Income on
Derivative(c)
Amount of Gain(Loss) Recognized
in Income on
Ameren:(d)
Operating Revenues - Electric
Interest Rate(e)
Operating Revenues - Electric -off-system
Operating Revenues - Electric - off-system
Genco:
Fair Value Hedges
During the third quarter ended September 30, 2008, UE entered into foreign currency forward contracts. These derivative instruments are intended to fix the amount of U.S. dollars UE will pay for future equipment deliveries and related services denominated in euros as part of a firm commitment to make payments related to heavy forgings. As of March 31, 2009, the total notional amounts of UE’s foreign currency contracts were €64 million. These forward contracts qualify as fair value hedges and, as a result, both the derivative positions and the foreign currency exposure on the firm commitment are recorded at fair value. Changes in the fair value of both the derivative instrument and the hedged item are recorded in earnings. For the quarter ended March 31, 2009, this hedging program was highly effective, resulting in no impact to net income.
Other Derivatives
The following table represents the net change in market value for derivatives not designated as hedging instruments under SFAS No. 133 for the three months ended March 31, 2009:
Derivatives Not Designated
as Hedging Instruments
under SFAS No. 133
Derivative
Amount of Gain (Loss)
Gas (generation)
Operating Expenses - Fuel
Gas (resale)
Operating Revenues - Gas
Total
Operating Revenues - Electric - excluding off-system
45
Derivatives Subject to Regulatory Deferral
The following table represents the net change in market value for derivatives that qualify for deferral under SFAS No. 71 for the three months ended March 31, 2009:
Amount of Gain or
(Loss) Recognized inRegulatory Assets orRegulatory Liabilitieson Derivative
UE, CIPS, CILCO, and IP believe gains and losses on derivatives deferred as regulatory assets and regulatory liabilities are probable of recovery through rates charged to customers. Regulatory assets and regulatory liabilities are amortized to operating expenses as related losses and gains are reflected in revenue through rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income.
As part of the electric rate order issued by the MoPSC in January 2009, UE was granted permission to implement a FAC, which was effective March 1, 2009. UE utilizes derivatives to mitigate its exposure to changing prices of fuel for generation and transportation costs and for power price volatility. In connection with the MoPSC’s approval of the FAC, gains and losses associated with these types of derivatives are considered refundable to or recoverable from customers and, thus, represent regulatory liabilities or regulatory assets, respectively, under SFAS No. 71. During the quarter ended March 31, 2009, UE recorded a net regulatory liability of $5 million associated with the reclassification of unrealized gains and losses previously recorded in accumulated OCI and earnings related to open UE derivative positions with delivery dates subsequent to March 1, 2009. The reclassification of previously recorded unrealized gains associated with the derivatives resulted in a $47 million reduction of accumulated OCI. The reclassification of previously recognized unrealized losses resulted in a $42 million increase in pre-tax earnings, of which $38 million offset fuel expense and $4 million increased operating revenues. See Note 2 - Rate and Regulatory Matters for additional information on the FAC.
As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company. These financial contracts are derivative instruments being accounted for as cash flow hedges at Marketing Company while they are being accounted for as derivatives subject to regulatory deferral at the Ameren Illinois Utilities. Consequently, the Ameren Illinois Utilities and Marketing Company record the fair value of the contracts on their respective balance sheets and the changes to the fair value in regulatory assets or liabilities for the Ameren Illinois Utilities and OCI at Marketing Company. In Ameren’s consolidated financial statements, all financial statement effects of the derivative instruments are eliminated. See Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K for additional information on these financial contracts.
NOTE 7 - FAIR VALUE MEASUREMENTS
SFAS No. 157 provides a framework for measuring fair value for all assets and liabilities that are measured and reported at fair value. The Ameren Companies adopted SFAS No. 157 as of the beginning of their 2008 fiscal year for financial assets and liabilities and as of the beginning of their 2009 fiscal year for nonfinancial assets and liabilities, except those already reported at fair value on a recurring basis. The impact of the adoption of SFAS No. 157 for financial assets and liabilities at January 1, 2008, and for nonfinancial assets and liabilities at January 1, 2009, was not material. SFAS No. 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. SFAS No. 157 also establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:
Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities primarily include exchange-traded derivatives and assets including U.S. treasury securities and listed equity securities, such as those held in UE’s Nuclear Decommissioning Trust Fund.
46
Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in UE’s Nuclear Decommissioning Trust Fund, including corporate bonds and other fixed-income securities, and certain over-the-counter derivative instruments, including natural gas swaps and financial power transactions. Derivative instruments classified as Level 2 are valued using corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint.
Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued based on internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable, including the financial contracts entered into between the Ameren Illinois Utilities and Marketing Company as part of the Illinois electric settlement agreement. We value Level 3 instruments using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, a review of all sources is performed to identify any anomalies or potential errors.
We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to SFAS No. 157. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.
We consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). SFAS No. 157 also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. Ameren recorded $7 million in losses in the first quarter of 2009 related to valuation adjustments for counterparty default risk. At March 31, 2009, the counterparty default risk valuation adjustment related to net derivative (assets) liabilities totaled $(4) million, $1 million, $17 million, $11 million, and $32 million for Ameren, UE, CIPS, CILCORP/CILCO and IP, respectively.
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of March 31, 2009:
Quoted Prices
in Active Markets
for IdentifiedAssets
(Level 1)
Significant
OtherObservable
Inputs
(Level 2)
Unobservable
(Level 3)
Assets:
Derivative assets(b)
Nuclear Decommissioning Trust Fund(c)
Derivative assets
Liabilities:
Derivative liabilities(b)
47
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2008:
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2009:
Realized
Change in
Unrealized
Gains (Losses)
Net derivative
contracts
Nuclear
Decommissioning Trust Fund
48
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2008:
Decommissioning
Trust Fund
Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers between Level 2 and Level 3 were primarily caused by changes in availability of financial power trades observable on electronic exchanges compared with previous periods for the quarters ended March 31, 2009 and 2008. Any reclassifications are reported as transfers in/out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur.
Related to our nonfinancial assets and liabilities, Note 14 - Goodwill Impairment details the inputs to the valuation of goodwill, which is considered a Level 3 asset, and the impairment charge recorded related to CILCORP’s goodwill. CILCORP’s goodwill is measured at fair value on a nonrecurring basis and was impaired during the first quarter of 2009. The following table sets forth, by level within the fair value hierarchy, CILCORP’s goodwill, as of March 31, 2009:
Quoted Prices in
Active Markets forIdentified Assets
Significant OtherObservable Inputs
Significant Other
Goodwill(a)
NOTE 8 - RELATED PARTY TRANSACTIONS
The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren’s financial statements. For a discussion of our material related party agreements, see Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K.
As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over four years as part of a comprehensive program providing approximately $1 billion of funding for rate relief to certain Illinois electric customers, including customers of the Ameren Illinois Utilities. At March 31, 2009, CIPS, CILCO and IP had receivable balances from Genco for reimbursement of customer rate relief of $1 million, less than $1 million, and $1 million, respectively. Also at March 31, 2009, CIPS, CILCO and IP had receivable balances from AERG for reimbursement of customer rate relief of less than $1 million each. During the three months ended March 31, 2009, Genco incurred charges to earnings of $2 million for customer rate relief contributions and program funding reimbursements to the Ameren Illinois Utilities (CIPS - $1 million, CILCO - less than $1 million, IP - $1 million), and AERG incurred charges to earnings of $1 million (less than $1 million at each of CIPS, CILCO and IP). The Ameren Illinois Utilities recorded most of the reimbursements received from Genco and AERG as electric revenue with an immaterial amount recorded as miscellaneous revenue.
49
Electric Power Supply Agreements
The following table presents the amount of physical gigawatthour sales under related party electric power supply agreements for the three months ended March 31, 2009 and 2008:
Genco sales to Marketing Company(a)
AERG sales to Marketing Company(a)
Marketing Company sales to CIPS(b)
Marketing Company sales to CILCO(b)
Marketing Company sales to IP(b)
Capacity Supply Agreements
CIPS, CILCO, and IP, as electric load serving entities, must acquire capacity sufficient to meet their obligations to customers. In 2009, the Ameren Illinois Utilities used a RFP process, administered by the IPA, to contract the necessary capacity for the period from June 1, 2009, through May 31, 2012. Both Marketing Company and UE were winning suppliers in the Ameren Illinois Utilities’ capacity RFP process. In April 2009, Marketing Company contracted to supply capacity to the Ameren Illinois Utilities for $4 million, $9 million, and $8 million for the twelve months ending May 31, 2010, 2011, and 2012, respectively. In April 2009, UE contracted to supply capacity to the Ameren Illinois Utilities for $2 million, $2 million, and $1 million for the twelve months ending May 31, 2010, 2011, and 2012, respectively.
Collateral Postings
Under the terms of the power supply agreements between Marketing Company and the Ameren Illinois Utilities, which were entered into as part of the September 2006 Illinois power procurement auction, cash collateral must be posted by Marketing Company under certain market conditions to protect the Ameren Illinois Utilities in the event of nonperformance by Marketing Company. The collateral postings are unilateral, meaning that Marketing Company as the supplier is the only counterparty required to post collateral. At March 31, 2009, and December 31, 2008, there were no collateral postings by Marketing Company related to the 2006 auction power supply agreements.
In addition, under the terms of the 2008 Illinois power procurement RFPs, cash collateral must be posted by Marketing Company and the Ameren Illinois Utilities under certain market conditions. The collateral postings are bilateral, meaning that either counterparty may be required to post collateral. As of March 31, 2009, the Ameren Illinois Utilities had cash collateral postings as follows with Marketing Company: CIPS - $5 million, CILCO - $3 million and IP - - $8 million. At December 31, 2008, the Ameren Illinois Utilities had cash collateral postings as follows with Marketing Company: CIPS - $7 million, CILCO - $4 million and IP - $11 million. These bilateral collateral postings were eliminated in consolidation on Ameren’s financial statements.
Generation Interconnection Agreement
In 2008, Genco and CIPS signed an agreement requiring Genco to fund the construction costs of upgrades to CIPS’ transmission system. At March 31, 2009, CIPS had recorded $2 million in Other Deferred Credits and Liabilities and Genco had recorded $2 million in Accounts Receivable - Affiliates. These transactions were eliminated in consolidation on Ameren’s financial statements.
See Note 3 - Short-term Borrowings and Liquidity for a discussion of affiliate borrowing arrangements.
CILCO Support Services
On January 1, 2009, approximately 570 Ameren Services employees who provided support services to the Ameren Illinois Utilities were transferred to CILCO. As CILCO employees, they provide services to CIPS and IP as well as to CILCO. The cost of support services provided by CILCO to CIPS and IP, including wages, employee benefits, professional services, and other expenses, are based on, or are an allocation of, actual costs incurred.
Intercompany Borrowings
Genco’s subordinated note payable to CIPS associated with the transfer in 2000 of CIPS’ electric generating assets and related liabilities to Genco matures on May 1, 2010. Interest income and expense for this note recorded by CIPS and Genco, respectively, was $2 million (2008 - $2 million) for the three months ended March 31, 2009.
CILCORP had outstanding borrowings from Ameren of $146 million and $152 million at March 31, 2009, and December 31, 2008, respectively. The balance at March 31, 2009, was issued under a unilateral borrowing agreement. See Note 3 - Short-term Borrowings and Liquidity for further information. The average interest rate on these borrowings was 1.7% for the three months ended March 31, 2009 (2008 - 4.4%). CILCORP recorded interest expense of less than $1 million for these borrowings for the three months ended March 31, 2009 (2008 - less than $1 million).
50
CILCO (AERG) had outstanding borrowings from Ameren of $100 million at March 31, 2009 under a unilateral borrowing agreement. See Note 3 - Short-term Borrowings and Liquidity for further information. The average interest rate on these borrowings was 1.7% for the three months ended March 31, 2009. CILCO (AERG) recorded interest expense of less than $1 million for these borrowings for the three months ended March 31, 2009.
UE had no outstanding borrowings directly from Ameren at March 31, 2009, and had outstanding borrowings directly from Ameren of $92 million at December 31, 2008. The average interest rate on these borrowings was 1.4% for the three months ended March 31, 2009 (2008 - 3.3%). UE recorded interest expense of less than $1 million for these borrowings for the three months ended March 31, 2009 (2008 - less than $1 million).
The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the three months ended March 31, 2009 and 2008. It is based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K, and the money pool arrangements discussed in Note 3 - Short-term Borrowings and Liquidity of this report.
Genco and AERG power supply
agreements with Marketing Company
Total Operating Revenues
Marketing Company(d)
with UE(c)
Total Purchased Power
Total Other Operations and Maintenance Expenses
51
Money pool borrowings (advances)
NOTE 9 - COMMITMENTS AND CONTINGENCIES
We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in these notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.
Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 14 - Related Party Transactions, and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 8 - Related Party Transactions and Note 10 - Callaway Nuclear Plant in this report.
Callaway Nuclear Plant
The following table presents insurance coverage at UE’s Callaway nuclear plant at March 31, 2009. The property coverage and the nuclear liability coverage must be renewed on October 1 and January 1, respectively, of each year.
Public liability and nuclear worker liability:
American Nuclear Insurers
Pool participation
Property damage:
Nuclear Electric Insurance Ltd.
Replacement power:
Energy Risk Assurance Company
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.
52
After the terrorist attacks on September 11, 2001, Nuclear Electric Insurance Ltd. confirmed that losses resulting from terrorist attacks would be covered under its policies. However, Nuclear Electric Insurance Ltd. imposed an industry-wide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.
If losses from a nuclear incident at the Callaway nuclear plant exceed the limits of, or are not subject to, insurance, or if coverage is unavailable, UE is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and UE’s results of operations, financial position, or liquidity.
Other Obligations
To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. We have also entered into various long-term commitments for the purchase of electric capacity and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K.
Our commitments for the procurement of coal have materially changed from amounts previously disclosed as of December 31, 2008. The following table presents our total estimated coal purchase commitments at March 31, 2009:
Our commitments for the procurement of natural gas have materially changed from amounts previously disclosed as of December 31, 2008. The following table presents our total estimated natural gas purchase commitments at March 31, 2009:
Our commitments for the purchase of electric capacity have materially changed from amounts previously disclosed as of December 31, 2008. At March 31, 2009, Ameren’s and UE’s 2009 electric capacity commitments were $9 million and $9 million, respectively. No electric capacity commitments existed beyond 2009 as of March 31, 2009.
Ameren Illinois Utilities’ Purchased Power Agreements
The IPA procured capacity through a RFP process on behalf of the Ameren Illinois Utilities in April 2009 for the period June 1, 2009 through May 31, 2012. The Ameren Illinois Utilities contracted to purchase between 800 and 3,500 MW of capacity per month at an average price of approximately $41 per MW-day over the three-year period. As a result, the Ameren Illinois Utilities’ commitments for the purchase of electric capacity will be $28 million, $26 million, $26 million and $1 million for 2009, 2010, 2011, and 2012, respectively.
The Illinois electric settlement agreement provides approximately $1 billion of funding over a four-year period that commenced in 2007 for rate relief for certain electric customers in Illinois. Funding for the settlement will come from electric generators in Illinois and certain Illinois electric utilities. The Ameren Illinois Utilities, Genco and AERG agreed to fund an aggregate of $150 million, of which the following contributions remained to be made as of March 31, 2009:
(Illinois
Regulated)
(AERG)
2009(a)
2010(a)
53
Environmental Matters
We are subject to various environmental laws and regulations enforced by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, natural gas storage plants, and natural gas transmission and distribution facilities, our activities involve compliance with diverse laws and regulations. These laws and regulations address noise, emissions, impacts to air and water, protected and cultural resources (such as wetlands, endangered species, and archeological and historical resources), and chemical and waste handling. Our activities often require complex and lengthy processes as we obtain approvals, permits or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or our operations. The more significant matters are discussed below.
Clean Air Act
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. In May 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean Air Mercury Rule). The federal Clean Air Interstate Rule requires generating facilities in 28 eastern states, including Missouri and Illinois where our generating facilities are located, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO2 emissions, annual NOx emissions, and ozone season NOx emissions. The cap-and-trade program for both annual and ozone season NOx emissions went into effect on January 1, 2009. The SO2 emissions cap-and-trade program is scheduled to take effect in 2010.
In February 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Mercury Rule. The court ruled that the EPA erred in the method it used to remove electric generating units from the list of sources subject to the maximum available control technology requirements under the Clean Air Act. In February 2009, the U.S. Supreme Court denied a petition for review filed by a group representing the electric utility industry. The impact of this decision is that the EPA will move forward with a MACT standard for mercury emissions. The standard is expected to be available in draft form in 2010, and compliance is expected to be required in the 2013 to 2015 timeframe. We cannot predict at this time the estimated capital costs for compliance with such future environmental rules.
In July 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Interstate Rule. The court ruled that the regulation contained several fatal flaws, including a regional cap-and-trade program that cannot be used to facilitate the attainment of ambient air quality standards for ozone and fine particulate matter. In September 2008, the EPA, as well as several environmental groups, a group representing the electric utility industry, and the National Mining Association, all filed petitions for rehearing with the U.S. Court of Appeals. In December 2008, the U.S. Court of Appeals essentially reversed its July 2008 decision to vacate the federal Clean Air Interstate Rule. The U.S. Court of Appeals granted the EPA petition for reconsideration and remanded the rule to the EPA for further action to remedy the rule’s flaws in accordance with the U.S. Court of Appeals’ July 2008 opinion in the case. The impact of the decision is that the existing Illinois and Missouri rules to implement the federal Clean Air Interstate Rule will remain in effect until the federal Clean Air Interstate Rule is revised by the EPA, at which point the Illinois and Missouri rules may be subject to change.
The state of Missouri has adopted state rules to implement the federal Clean Air Interstate Rule for regulating SO2 and NOx emissions from electric generating units. The rules are a significant part of Missouri’s plan to attain existing ambient standards for ozone and fine particulates, as well as meeting the federal Clean Air Visibility Rule. The rules are expected to reduce NOx emissions 30% and SO2 emissions 75% by 2015. As a result of the Missouri rules, UE will manage allowances and install pollution control equipment. UE’s costs to comply with SO2 emission reductions required by the Clean Air Interstate Rule could increase materially if the EPA determines that existing allowances granted to sources under the Acid Rain Program cannot be used for compliance with the Clean Air Interstate Rule or if a new allowance program is mandated by revisions to the Clean Air Interstate Rule. Missouri also adopted state rules to implement the federal Clean Air Mercury Rule. However, those state rules are not enforceable as a result of the U.S. Court of Appeals decision to vacate the federal Clean Air Mercury Rule.
We do not believe that the court decision that vacated the federal Clean Air Mercury Rule will significantly affect pollution control obligations in Illinois in the near term. Under the MPS, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90%, in exchange for accelerated installation of NOx and SO2 controls. To comply with the rule, Genco, CILCO (AERG) and EEI have begun putting into service equipment designed to reduce mercury emissions. This rule, when fully implemented, is expected to reduce mercury emissions 90%, NOx emissions 50%, and SO2emissions 70% by 2015 in Illinois. As a result of the Illinois rules, Genco, AERG and EEI will need to install pollution control equipment. Current plans include installing scrubbers for SO2 reduction as well as optimizing operations of selective catalytic reduction (SCR) systems for NOxreduction at certain coal-fired plants in Illinois.
54
In October 2008, Genco, CILCO (AERG) and EEI submitted a request for a variance from the MPS to the Illinois Pollution Control Board. In preparing this request, Genco, CILCO (AERG) and EEI worked with the Illinois EPA and agreed to the installation of more stringent SO2 and NOx controls at various stages between 2010 and 2020 in order to make the variance proposal “environmentally neutral.” In January 2009, the Illinois Pollution Control Board denied the variance request on procedural grounds. Genco, CILCO (AERG) and EEI filed a motion for reconsideration in February 2009. With the Illinois EPA’s concurrence, they then sought to amend the MPS within a pending rulemaking pertaining to technical amendments of the underlying mercury regulations. In April 2009, the Illinois Pollution Control Board approved the revisions to the MPS within that rulemaking, subject to Illinois Joint Committee on Administrative Rules review and approval. This review is expected in the second quarter of 2009. This rule amendment would allow Genco to defer an estimated $375 million of environmental capital expenditures from the 2009-2012 timeframe to the 2013-2015 timeframe. This estimate is subject to change based on the format of the final rule and our plans for compliance.
In March 2008, the EPA finalized regulations that will lower the ambient standard for ozone. Illinois and Missouri have each submitted their recommendations to the EPA for designating nonattainment areas. A final action by the EPA to designate nonattainment areas is expected in March 2010. State implementation plans will need to be submitted in 2013 unless Illinois and Missouri seek extensions for various requirement dates. Additional emission reductions may be required as a result of future state implementation plans. At this time, we are unable to determine the impact such state actions would have on our results of operations, financial position, or liquidity.
The table below presents estimated capital costs that are based on current technology to comply with the federal Clean Air Interstate Rule and related state implementation plans through 2018, as well as federal ambient air quality standards including ozone and fine particulates, and the federal Clean Air Visibility rule. The estimates described below could change depending upon additional federal or state requirements, the requirements under a mercury MACT standard, whether the rule amendment request with respect to the Illinois MPS discussed above is approved, new technology, variations in costs of material or labor, or alternative compliance strategies, among other reasons. The timing of estimated capital costs may also be influenced by whether emission allowances are used to comply with any future rules, thereby deferring capital investment.
UE(a)
Emission Allowances
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. The Clean Air Act created marketable commodities called allowances under the Acid Rain Program, the NOx Budget Trading Program, and the federal Clean Air Interstate Rule. All existing generating facilities have been allocated allowances based on past production and the statutory emission reduction goals. NOx allowances allocated under the NOx Budget Trading Program can be used for the seasonal NOx program under the federal Clean Air Interstate Rule. Our generating facilities comply with the SO2 limits through the use and purchase of allowances, through the use of low-sulfur fuels, and through the application of pollution control technology. Our generating facilities are expected to comply with the NOx limits through the use and purchase of allowances or through the application of pollution control technology, including low-NOx burners, over-fire air systems, combustion optimization, rich-reagent injection, selective noncatalytic reduction, and selective catalytic reduction systems.
See Note 1 - Summary of Significant Accounting Policies for the SO2 and NOx emission allowances held and the related SO2 and NOxemission allowance book values that were carried as intangible assets as of March 31, 2009.
UE, Genco, CILCO and EEI expect to use a substantial portion of the SO2 and NOx allowances for ongoing operations. Environmental regulations, including the Clean Air Interstate Rule, the timing of the installation of pollution control equipment, and the level of operations, will have a significant impact on the number of allowances actually required for ongoing operations. The Clean Air Interstate Rule requires a reduction in SO2 emissions by increasing the ratio of Acid Rain Program allowances surrendered. The current Acid Rain Program requires the surrender of one SO2 allowance for every ton of SO2 that is emitted. Unless revised by the EPA as a result of the U.S. Court of Appeals’ remand, the Clean Air Interstate Rule program will require that SO2 allowances of vintages 2010 through 2014 be surrendered at a ratio of two allowances for every ton of emission. SO2 allowances with vintages of 2015 and beyond will be required to be surrendered at a ratio of 2.86 allowances for every ton of emission. In order to accommodate this change in surrender ratio and to comply with the federal and state regulations, UE, Genco, AERG, and EEI expect to install control technology designed to further reduce SO2 emissions, as discussed above.
55
The Clean Air Interstate Rule has both an ozone season program and an annual program for regulating NOx emissions, with separate allowances issued for each program. The Clean Air Interstate Rule ozone season program replaced the NOx Budget Trading Program beginning in 2009. Both sets of allowances for the years 2009 through 2014 were issued by the Missouri Department of Natural Resources in December 2007. Allocations for UE’s Missouri generating facilities were 11,665 tons per ozone season and 26,842 tons annually. Allocations for Genco’s generating facility in Missouri were one ton for the ozone season and three tons annually. Both sets of allowances for the years 2009 through 2011 were issued by the Illinois EPA in April 2008. Allocations for UE’s, Genco’s, AERG’s, and EEI’s Illinois generating facilities were 90, 3,442, 1,368, and 1,758 tons per ozone season, respectively, and 93, 8,300, 3,418, and 4,564 tons annually, respectively.
Global Climate
Future initiatives regarding greenhouse gas emissions and global warming are subject to active consideration in the U.S. Congress. In March 2009, the U.S. House of Representatives Committee on Energy and Commerce, Subcommittee on Energy and the Environment, issued a draft energy bill that included climate legislation. The climate legislation proposes establishing an economy-wide cap-and-trade program. The overarching goal of such legislation is to reduce greenhouse gas emissions to a level that is 20% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by the year 2050. The draft legislation also contains a renewable energy standard of 25% by the year 2025 and an energy efficiency mandate for both electric and gas utilities, as well as other requirements.
President Obama supports an economy-wide cap-and- trade greenhouse gas reduction program that would reduce emissions to 14% below 2005 levels by 2020 and to 80% below 2005 levels by 2050. President Obama has also indicated support for auctioning 100% of the emission allowances to be distributed under the legislation. However, recent statements from the Obama administration indicate a willingness to support some level of emission allowance allocation. Although we cannot predict the date of enactment or the requirements of any climate legislation, it is likely that some form of federal climate legislation will become law during the Obama administration.
Potential impacts from proposed legislation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of allocating allowances, and provisions for cost containment measures, such as a “safety valve” that provides a ceiling price for emission allowance purchases. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities, but coal-fired power plants are significant sources of CO2, a principal greenhouse gas. Ameren’s current analysis shows that under some policy scenarios being considered in the U.S. Congress, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and the Midwest economy because of the region's reliance on electricity generated by coal-fired power plants. Natural gas emits about half the amount of CO2 that coal emits when burned to produce electricity. As a result, economy-wide shifts favoring natural gas as a fuel source for electric generation also could affect the cost of heating for our utility customers and many industrial processes. Under some policy scenarios being considered by Congress, Ameren believes that wholesale natural gas costs could rise significantly as well. Higher costs for energy could contribute to reduced demand for electricity and natural gas.
Future initiatives regarding greenhouse gas emissions and global warming may also be subject to the activities pursuant to the Midwest Greenhouse Gas Reduction Accord, an agreement signed by the governors of Illinois, Iowa, Kansas, Michigan, Wisconsin and Minnesota to develop a strategy to achieve energy security and to reduce greenhouse gas emissions through a cap-and-trade mechanism. It is expected that the advisory group to the Midwest governors will provide recommendations on the design of a greenhouse gas reduction program by the third quarter of 2009. However, it is uncertain whether legislation to implement the recommendations will be implemented or passed by any of the states, including Illinois.
With regard to greenhouse gas regulation under existing law, in April 2007, the U.S. Supreme Court issued a decision that the EPA has the authority to regulate CO2 and other greenhouse gases from automobiles as “air pollutants” under the Clean Air Act. This decision was a result of a Bush Administration ruling denying a waiver request by the state of California to implement such regulations. The Supreme Court sent the case back to the EPA, which must conduct a rulemaking process to determine whether greenhouse gas emissions contribute to climate change “which may reasonably be anticipated to endanger public health or welfare.” In April 2009, the EPA issued a proposed finding that greenhouse gases contribute to air pollution that may endanger public health or welfare. The EPA plans to take comments on its proposed findings and hold hearings. It is anticipated that the endangerment finding could enable states to regulate greenhouse gas emissions from automobiles. It could also set in motion the process of establishing emission limitations for power plants and other industrial sources of greenhouse gasses. This endangerment finding is expected to be final by the end of 2009. However, specific regulations governing power plants and other sources would be developed in subsequent rulemakings and may be preempted by federal legislative actions.
56
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs, which in turn could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force UE, Genco, CILCO (through AERG) and EEI as well as other similarly situated electric power generators to close some coal-fired facilities. As a result, mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, AERG’s and EEI’s results of operations, financial position, or liquidity.
The impact on us of future initiatives related to greenhouse gas emissions and global warming is unknown. Although compliance costs are unlikely in the near future, our costs of complying with any mandated federal or state greenhouse gas program could have a material impact on our future results of operations, financial position, or liquidity.
Clean Water Act
In July 2004, the EPA issued rules under the Clean Water Act that require cooling-water intake structures to have the best technology available for minimizing adverse environmental impacts on aquatic species. These rules pertain to all existing generating facilities that currently employ a cooling-water intake structure whose flow exceeds 50 million gallons per day. The rules may require facilities to install additional intake screens or other protective measures and to do extensive site-specific study and monitoring. There is also the possibility that the rules may lead to the installation of cooling towers on some of our generating facilities. On April 1, 2009, the U.S. Supreme Court ruled that the EPA can compare costs for existing power plants to use the best available technology to protect aquatic species against environmental benefits in enforcing the Clean Water Act. The EPA is expected to propose revised rules in late summer or early fall of 2009. Until the EPA reissues the rules, the reissued rules are adopted, and the studies on the power plants are completed, we are unable to estimate the costs of complying with these rules. Such costs are not expected to be incurred prior to 2012.
New Source Review
The EPA has been conducting an enforcement initiative to determine whether modifications at a number of coal-fired power plants owned by electric utilities in the United States are subject to New Source Review (NSR) requirements or New Source Performance Standards under the Clean Air Act. The EPA’s inquiries focus on whether the best available emission control technology was or should have been used at such power plants when major maintenance or capital improvements were performed.
In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act. It sought detailed operating and maintenance history data with respect to Genco’s Coffeen, Hutsonville, Meredosia and Newton facilities, EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. In December 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton facility. All of these facilities are coal-fired power plants. In September 2008, the EPA issued a third Section 114(a) request regarding projects at all of Ameren’s Illinois coal-fired power plants. We are complying with this information request, but we are unable to predict the outcome of this matter.
In March 2008, Ameren received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act seeking detailed operating and maintenance history data with respect to UE’s Labadie, Meramec, Rush Island, and Sioux facilities. All of these facilities are coal-fired power plants. The information request required UE to provide responses to specific EPA questions regarding certain projects and maintenance activities in order to determine UE’s compliance with state and federal regulatory requirements. UE is complying with this information request, but we are unable to predict the outcome of this matter.
Resolution of these matters could have a material adverse impact on the future results of operations, financial position, or liquidity of Ameren, UE, Genco, AERG and EEI. A resolution could result in increased capital expenditures for the installation of control technology, increased operations and maintenance expenses, and fines or penalties.
Remediation
We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site. UE, CIPS, CILCO and IP have each been identified by the federal or state governments as a potentially responsible party (PRP) at several contaminated sites. Several of these sites involve facilities that were transferred by CIPS to Genco in May 2000 and facilities transferred by CILCO to AERG in October 2003. As part of each transfer, CIPS and CILCO have contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.
As of March 31, 2009, CIPS, CILCO and IP owned or were otherwise responsible for several former MGP sites in Illinois. CIPS has 14, CILCO 4, and IP 25 sites. All of these sites are in various stages of investigation, evaluation and remediation. Ameren
57
currently anticipates that remediation at these sites should be completed by 2015. The ICC permits each company to recover remediation and litigation costs associated with its former MGP sites from its Illinois electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred, and costs are subject to annual reconciliation review by the ICC. As of March 31, 2009, estimated obligations were: CIPS - $17 million to $28 million, CILCO - $6 million to $13 million, IP - $74 million to $143 million. CIPS, CILCO and IP have liabilities of $17 million, $6 million, and $74 million, respectively, recorded to represent estimated minimum obligations, as no other amount within the range was a better estimate.
CIPS is also responsible for the cleanup of a former landfill in Coffeen, Illinois. As of March 31, 2009, CIPS estimated its obligation at $0.5 million to $6 million. CIPS recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. IP is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of March 31, 2009, IP recorded a liability of $1 million to represent its best estimate of the obligation for these sites.
In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one site in Iowa. UE does not currently have in effect in Missouri a rate rider mechanism that permits remediation costs associated with MGP sites to be recovered from utility customers. See Note 2 - Rate and Regulatory Matters for information on a Missouri law enabling the MoPSC to put in place environmental cost recovery mechanisms for Missouri utilities. UE does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs. As of March 31, 2009, UE estimated its obligation at $3 million to $4 million. UE has a liability of $3 million recorded to represent its estimated minimum obligation for its MGP sites, as no other amount within the range was a better estimate. UE also is responsible for four electric sites in Missouri that have corporate cleanup liability, most as a result of federal agency mandates.
In June 2000, the EPA notified UE and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, UE operated a power generating facility adjacent to Sauget Area 2. UE currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order and Consent, UE has joined with other PRPs to evaluate the extent of potential contamination with respect to Sauget Area 2.
Sauget Area 2 investigations overseen by the EPA are largely completed, and the results will be submitted to the EPA in June 2009. Following this submission, the EPA will ultimately select a remedy alternative and begin negotiations with various PRPs to implement it. Over the last several years, numerous other parties have joined the PRP group and presumably will participate in the funding of any required remediation. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia’s former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia’s filing for bankruptcy protection. As of March 31, 2009, UE estimated its obligation at $1 million to $10 million. UE has a liability of $1 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.
In March 2008, the EPA issued an administrative order requesting that CIPS participate in a portion of an environmental cleanup of a site within Sauget Area 2 previously occupied by Clayton Chemical Company. CIPS was formerly a customer of Clayton Chemical Company, which before its dissolution was a recycler of waste solvents and oil. Other former customers of Clayton Chemical Company were issued similar orders by the EPA. Pursuant to that order, CIPS and three other PRPs agreed to install an engineered barrier on portions of the Clayton Chemical Company site. This work was concluded in the first quarter of 2009. As of March 31, 2009, CIPS has a liability of $0.2 million recorded to represent its best estimate of its obligation for this site.
In July 2008, the EPA issued an administrative order to UE pertaining to a former coal tar distillery operated by Koppers Company or its predecessor and successor companies. UE is the current owner of the site but did not conduct any of the manufacturing operations involving coal tar or its byproducts. UE is currently in negotiations with other PRPs concerning the scope of future site investigations. As of March 31, 2009, UE estimated its obligation at $2 million to $5 million. UE has a liability of $2 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.
In December 2004, AERG submitted a comprehensive package to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek power plant facility. Information submitted by AERG is currently under review by the Illinois EPA. CILCORP and CILCO both have a liability of $1.8 million at March 31, 2009, on their consolidated balance sheets for the estimated cost of the remediation effort, which involves treating and discharging recycle-system water in order to address these groundwater and surface water issues.
58
In March 2009, UE and CIPS received from the EPA “Special Notice of Liability” letters with respect to a former transformer repair facility located in Cape Girardeau, Missouri. Both companies are members of a PRP group that sent electrical equipment to the site and previously performed certain soil remediation and investigative work with respect to the site. The EPA is requesting the PRP group to investigate groundwater conditions at the site and the group is in the process of negotiating the terms under which such additional work would occur. UE and CIPS believe that the PRP group presently has adequate financial resources to cover the cost of such work without additional contributions from the companies.
In addition, our operations or those of our predecessor companies involve the use, disposal of, and in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine whether such practices will result in future environmental commitments or impact our results of operations, financial position, or liquidity.
Ash Ponds
There has been increased activity at both the state and federal level to examine the need for additional regulation of utility ash pond facilities and coal-combustion wastes. Ameren received and responded to an information collection request from the EPA in March 2009. The EPA sent the information collection request to numerous utilities in the country. It is anticipated that some form of additional regulation concerning the integrity of ash ponds and the handling and disposal of coal combustion waste may be forthcoming within the next two years. In addition, the Illinois EPA has requested that UE, Genco, CILCO (AERG) and EEI establish groundwater monitoring plans for their active and inactive ash impoundments. At this time, we are unable to predict the outcome any such regulations might have on our results of operations, financial position, or liquidity.
Pumped-storage Hydroelectric Facility Breach
In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park.
UE has settled with FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident. In addition, UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant and has begun rebuilding the facility. The estimated cost to rebuild the upper reservoir is in the range of $480 million. UE expects the Taum Sauk plant to be out of service through early 2010.
In December 2006, 11 business owners filed a lawsuit regarding the Taum Sauk breach. The suit, which was filed in the Missouri Circuit Court of Reynolds County, contained allegations of negligence, violations of the Missouri Clean Water Act, and various other statutory and common law claims. It sought damages relating to business losses, lost profit, and unspecified punitive damages. In April 2009, UE completed a settlement with the business owners for an amount not material to UE and the court dismissed the lawsuit with prejudice.
In December 2008, the Department of the Army, Corps of Engineers filed a lawsuit regarding the Taum Sauk breach. The suit, which was filed in the U.S. District Court in Cape Girardeau, Missouri, claimed that Clearwater Lake in southeastern Missouri was damaged by sediment from the Taum Sauk breach. In April 2009, in response to the Corps of Engineers’ motion, the court dismissed the lawsuit without prejudice to the Corps of Engineers’ right to refile the lawsuit. UE cannot predict whether the lawsuit will be refiled.
At this time, UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the facility, and the cost of replacement power, up to $8 million annually, will be covered by insurance. Insurance will not cover lost electric margins and penalties paid to FERC. UE expects that the total cost for cleanup, damage and liabilities, excluding costs to rebuild the reservoir, will range from $200 million to $220 million. As of March 31, 2009, UE had paid $187 million, including costs resulting from the FERC-approved stipulation and consent agreement. UE accrued a $13 million liability while expensing $33 million and recording a $167 million receivable due from insurance companies. As of March 31, 2009, UE had received $85 million from insurance companies, which reduced the insurance receivable balance to $82 million.
As of March 31, 2009, UE had recorded a $367 million receivable due from insurance companies related to the rebuilding of the facility and the reimbursement of replacement power costs. As of March 31, 2009, UE had received $176 million from insurance companies, which reduced the insurance receivable balance as of March 31, 2009, to $191 million.
Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. Until the insurance review is completed, among other things, we are unable to determine the total impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.
Asbestos-related Litigation
Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County,
59
Illinois. The total number of defendants named in each case is significant; as many as 192 parties are named in some pending cases and as few as six in others. However, in the cases that were pending as of March 31, 2009, the average number of parties was 71.
The claims filed against Ameren, UE, CIPS, Genco, CILCO and IP allege injury from asbestos exposure during the plaintiffs’ activities at our present or former electric generating plants. Former CIPS plants are now owned by Genco, and former CILCO plants are now owned by AERG. Most of IP’s plants were transferred to a former parent subsidiary prior to Ameren’s acquisition of IP. As a part of the transfer of ownership of the CIPS and CILCO generating plants, CIPS and CILCO have contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.
The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of March 31, 2009:
As of March 31, 2009, six asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.
At March 31, 2009, Ameren, UE, CIPS, CILCO and IP had liabilities of $12 million, $3 million, $3 million, $1 million and $5 million, respectively, recorded to represent their best estimate of their obligations related to asbestos claims.
IP has a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms. Beginning in 2007, 90% of cash expenditures in excess of the amount included in base electric rates are recovered by IP from a trust fund established by IP. At March 31, 2009, the trust fund balance was approximately $23 million, including accumulated interest.
If cash expenditures are less than the amount in base rates, IP will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider.
The Ameren Companies believe that the final disposition of these proceedings will not have a material adverse effect on their results of operations, financial position, or liquidity.
NOTE 10 - CALLAWAY NUCLEAR PLANT
Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill, or 1/10 of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel. Pursuant to this act, UE collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway nuclear plant. Electric utility rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available before 2020. UE has sufficient installed storage capacity at its Callaway nuclear plant until 2020. It has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE’s disposal facility is not expected to adversely affect the continued operation of the Callaway nuclear plant through its currently licensed life.
Electric utility rates charged to customers provide for the recovery of the Callaway nuclear plant’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the plant, ending with the expiration of the plant’s operating license in 2024. UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license to 2044. It is assumed that the Callaway nuclear plant site will be decommissioned based on the immediate dismantlement method and removal from service. Ameren and UE have recorded an ARO for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are charged to the costs of service used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2008, 2007 and 2006. Every three years, the MoPSC requires UE to file an updated cost study for decommissioning its Callaway nuclear plant. Electric rates may be adjusted at such times to reflect changed estimates. The latest cost study was filed in September 2008. The 2008 study included the minor tritium contamination discovered on the Callaway nuclear plant site, which did not result in a significant increase in the decommissioning cost estimate. Costs collected from customers are deposited in an external trust fund to provide for the Callaway nuclear plant’s decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for UE’s Callaway nuclear plant is reported as Nuclear Decommissioning Trust Fund in Ameren’s Consolidated Balance Sheet and UE’s Balance Sheet. This amount is legally restricted. It may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund and to a regulatory asset or regulatory liability, as appropriate.
60
See Note 2 - Rate and Regulatory Matters for information on the suspension of UE’s efforts to build a new nuclear unit at its existing Callaway nuclear plant site.
NOTE 11 - OTHER COMPREHENSIVE INCOME
Comprehensive income includes net income as reported on the statements of income and all other changes in common stockholders’ equity, except those resulting from transactions with common stockholders. A reconciliation of net income to comprehensive income for the three months ended March 31, 2009 and 2008, is shown below for the Ameren Companies:
Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $44 and $(36), respectively
Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $26 and $(3), respectively
Reclassification adjustment due to implementation of FAC, net of taxes of $18 and $-, respectively
Adjustment to pension and benefit obligation, net of taxes (benefit) of $- and $(2), respectively
Total comprehensive income, net of taxes
Less: Net income attributable to noncontrolling interests, net of taxes
Total comprehensive income attributable to Ameren Corporation, net of taxes
Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $11 and $(7), respectively
Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $8 and $(1), respectively
Total comprehensive income (loss), net of taxes
Unrealized net (loss) on derivative hedging instruments, net of taxes (benefit) of $- and $(4), respectively
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $- and $-, respectively
NOTE 12 - RETIREMENT BENEFITS
Ameren’s pension and postretirement plans are funded in compliance with income tax regulations and to achieve federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Taking into consideration our assumptions at December 31, 2008, the investment performance in 2008, and our pension funding policy, Ameren expects to make annual contributions of $90 million to $200 million in each of the next five years. These amounts are estimates. They may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.
61
The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit plans for the three months ended March 31, 2009 and 2008:
Service cost
Interest cost
Expected return on plan assets
Amortization of:
Transition obligation
Prior service cost (benefit)
Actuarial loss
Net periodic benefit cost
UE, CIPS, Genco, CILCORP, CILCO and IP are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three months ended March 31, 2009 and 2008:
NOTE 13 - SEGMENT INFORMATION
Ameren has three reportable segments: Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. The Missouri Regulated segment for Ameren includes all the operations of UE’s business as described in Note 1 - Summary of Significant Accounting Policies, except for UE’s 40% interest in EEI (which in February 2008 was transferred to Resources Company through an internal reorganization). The Illinois Regulated segment for Ameren consists of the regulated electric and gas transmission and distribution businesses of CIPS, CILCO, and IP, as described in Note 1 - Summary of Significant Accounting Policies. The Non-rate-regulated Generation segment for Ameren consists primarily of the operations or activities of Genco, the CILCORP parent company, AERG, EEI, and Marketing Company. The category called Other primarily includes Ameren parent company activities.
UE has one reportable segment: Missouri Regulated. The Missouri Regulated segment for UE includes all the operations of UE’s business as described in Note 1 - Summary of Significant Accounting Policies, except for UE’s former 40% interest in EEI.
CILCORP and CILCO have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. The Illinois Regulated segment for CILCORP and CILCO consists of the regulated electric and gas transmission and distribution businesses of CILCO. The Non-rate-regulated Generation segment for CILCORP and CILCO consists of the generation business of AERG. For CILCORP and CILCO, Other comprises parent company activity and minor activities not reported in the Illinois Regulated or Non-rate-regulated Generation segments for CILCORP.
62
The following tables present information about the reported revenues and specified items included in net income of Ameren, UE, CILCORP, and CILCO for the three months ended March 31, 2009 and 2008, and total assets as of March 31, 2009, and December 31, 2008.
2009:
External revenues
Intersegment revenues
Net income attributableto Ameren Corporation(a)
2008:
Net income (loss)attributable to Ameren Corporation(a)
As of March 31, 2009:
As of December 31, 2008:
Revenues
Net income(b)
Intersegment
Eliminations
Consolidated
Goodwill impairment(a)
Net loss(b)
Total assets(c)
63
Net income(a)
Net income (loss)(a)
NOTE 14 - GOODWILL IMPAIRMENT
We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Goodwill impairment testing is a two-step process. The first step involves a comparison of the estimated fair value of a reporting unit with its carrying amount. If the estimated fair value of the reporting unit exceeds the carrying value, goodwill of the reporting unit is considered unimpaired. If the carrying amount of the reporting unit exceeds its estimated fair value, the second step is performed to measure the amount of impairment, if any. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined by allocating the estimated fair value of the reporting unit to the estimated fair value of its existing assets and liabilities in a manner similar to a purchase price allocation. The unallocated portion of the estimated fair value of the reporting unit is the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss, equivalent to the difference, is recorded as a reduction of goodwill and a charge to operating expense.
The goodwill impairment test that we performed in the fourth quarter of 2008 did not result in the second step assessment; the test indicated no impairment of Ameren’s, CILCORP’s, or IP’s goodwill. However, the estimated fair values of both of CILCORP’s reporting units (Illinois Regulated and Non-rate-regulated Generation) exceeded carrying values by a nominal amount. We concluded that events had occurred and circumstances had changed during the first quarter of 2009, which required us to perform an interim goodwill impairment test. The following triggering events resulted in the need for us to perform an impairment test:
A significant decline in Ameren’s market capitalization.
The continuing decline in market prices for electricity.
A decrease in observable industry market multiples.
The fair value of Ameren’s, CILCORP’s and IP’s reporting units was estimated based on a risk-adjusted, probability-weighted discounted cash flow model that considered multiple operating scenarios. Key assumptions in the determination of fair value included the use of an appropriate discount rate, estimated five-year future cash flows, and an exit value based on observable industry market multiples. For the interim test conducted as of March 31, 2009, the discount rate used was 3.8%, based on the twenty-year treasury yield. To assess the reasonableness of the estimated fair values, the sum of the estimated fair values of the Ameren reporting units is reconciled to our current market capitalization plus an estimated control premium. We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, the regulatory environment, and operating costs.
As a result of this interim impairment test, CILCORP’s Illinois Regulated reporting unit and CILCORP’s Non-rate-regulated Generation reporting unit both failed step one as each reporting unit’s carrying value exceeded its estimated fair value. Therefore, in order to measure the amount of any goodwill impairment in step two, we estimated individually the implied fair value of CILCORP’s Illinois Regulated goodwill and CILCORP’s Non-rate-regulated Generation goodwill. We determined that the implied fair value of goodwill was less than the carrying amount of goodwill for both reporting units, indicating that CILCORP’s Illinois Regulated goodwill and CILCORP’s Non-rate-regulated Generation goodwill was impaired as of March 31, 2009. Based on the results of step
64
two, CILCORP recorded an impairment charge of $462 million, which represented all of the goodwill assigned to CILCORP’s Non-rate-regulated Generation reporting unit of $345 million and $117 million assigned to CILCORP’s Illinois Regulated reporting unit. The step two test indicated that the implied fair value of goodwill relating to CILCORP’s Illinois Regulated reporting unit was $80 million.
The goodwill impairment recorded at CILCORP was not reflected at the consolidated Ameren level because of the aggregation of reporting units. Ameren’s reporting units and IP’s reporting unit did not require a second step assessment; the results of the step one tests indicated no impairment of goodwill as of March 31, 2009. However, the estimated fair values of Ameren’s Illinois Regulated reporting unit, Ameren’s Non-rate-regulated Generation reporting unit, and IP’s Illinois Regulated reporting unit exceeded carrying values by a nominal amount as of March 31, 2009. The estimated fair value of Ameren’s Illinois Regulated reporting unit exceeded its carrying value by approximately $210 million, or 5% of its carrying value. The estimated fair value of Ameren’s Non-rate-regulated Generation reporting unit exceeded its carrying value by approximately $35 million, or 1% of its carrying value. The estimated fair value of IP’s Illinois Regulated reporting unit exceeded its carrying value by approximately $100 million, or 4% of its carrying value. As a result, the failure in the future of any reporting unit to achieve forecasted operating results and cash flows or a further decline of observable industry market multiples may reduce its estimated fair value below its carrying value and would likely result in the recognition of a goodwill impairment charge.
Ameren, CILCORP and IP will continue to monitor the actual and forecasted operating results, cash flows, market capitalization, market prices for electricity and observable industry market multiples of their reporting units for signs of possible declines in estimated fair value and potential goodwill impairment.
The following tables detail how goodwill has been assigned to the registrants’ reporting units and changes to the carrying amount of goodwill as of March 31, 2009:
Regulated
Non-rate-regulated
Generation
Balance at December 31, 2008
Impairment loss
Balance at March 31, 2009
The following discussion should be read in conjunction with the financial statements contained in this Form 10-Q as well as Management’s Discussion and Analysis of Financial Condition and Results of Operations and Risk Factors contained in the Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements, and the primary factors that accounted for those changes, as well as how certain accounting principles affect our financial statements. The discussion also provides information about the financial results of the various segments of our business to provide a better understanding of how those segments and their results affect the financial condition and results of operations of Ameren as a whole.
65
OVERVIEW
Ameren Executive Summary
Ameren’s earnings in the first quarter of 2009 of $141 million, or $0.66 per share, were comparable with its earnings in the first quarter of 2008 of $138 million, or $0.66 per share. First quarter earnings in 2009 were favorably impacted by unrealized MTM activity on derivatives and the benefit to earnings of new utility service rates in Illinois, effective October 1, 2008, and in Missouri, effective March 1, 2009, among other positive factors. Offsetting these factors in the first quarter of 2009 were lower electric and gas sales volumes, higher fuel and related transportation prices, the impact of a severe winter ice storm, and the effect of seasonal gas delivery service rate redesign for the Ameren Illinois Utilities.
Milder weather and the absence of a leap day in 2009 contributed to a 6% decline in kilowatthour sales to residential customers and a 2% decline in kilowatthour sales to commercial customers. Absent these factors, we estimate that first quarter 2009 residential and commercial kilowatthour sales each declined 1% versus the year-ago period. The weak economy significantly impacted industrial electric sales. Industrial sales declined 13% from the year-ago quarter, excluding the impact of a storm-related loss of operating capacity at UE’s largest customer, Noranda. While this industrial decline was significant, sales to these customers represented only 16% of UE’s and only 6% of the Ameren Illinois Utilities’ native load electric revenues in 2008. In addition, such sales are relatively low margin.
With respect to operations, UE’s equivalent availability for its coal-fired generating units was 90% in the first quarter of 2009, which was comparable to the first quarter 2008 level. However, UE’s Callaway nuclear plant experienced a 12-day unplanned outage in the first quarter of 2009. Non-rate-regulated Generation’s equivalent availability for its coal-fired units was 81% for the first quarter of 2009 compared with 85% in the same year-ago period. This decline reflects a planned outage to complete installation of a multi-pollutant control system and major maintenance at its Duck Creek power plant. This planned outage, as well as lower market prices for power and reduced generation at another of its plants due to MISO system transmission congestion issues, resulted in a decline in generation output. While Non-rate-regulated Generation’s volumes were down in the quarter, its electric margin was only down slightly due to proactive physical sales and financial hedges of 2009 generation made in prior years at higher-than-current market prices.
UE had been investing in a nuclear COLA and heavy forgings for a possible second nuclear unit at its existing Callaway site to preserve a nuclear generation option for meeting its customers’ future energy needs toward the end of the next decade. In April 2009, UE suspended those efforts because proposed legislation in the Missouri General Assembly that would have allowed utilities to recover financing costs from customers while building a new plant had been stripped of the provisions UE needed to move forward. UE will consider all available and feasible generation options to meet future customer requirements as part of an updated integrated resource plan that UE is due to file with the MoPSC in June 2010. In the meantime, UE is assessing all options to maximize the value of its investment in this project.
CILCORP recognized a goodwill impairment loss of $462 million during the first quarter of 2009 due to a significant decline in Ameren’s market capitalization, the continuing decline in market prices for electricity, and a decrease in observable industry market multiples. CILCORP’s impairment charge did not result in a goodwill impairment charge at the consolidated Ameren level. However, the estimated fair values of Ameren’s Illinois Regulated reporting unit, Ameren’s Non-rate-regulated Generation reporting unit, and IP’s Illinois Regulated reporting unit exceeded their carrying value by a nominal amount as of March 31, 2009. As a result, the failure in the future of any reporting unit to achieve forecasted operating results and cash flows or a further decline of observable industry market multiples may reduce its estimated fair value below its carrying value and would likely result in the recognition of a goodwill impairment charge. We will continue to monitor the actual and forecasted operating results, cash flows, market capitalization, market prices for electricity, and observable industry market multiples of these reporting units for signs of possible declines in estimated fair value and potential goodwill impairment.
Outlook
The global capital and credit markets experienced extreme volatility and disruption in 2008 and early 2009, and we expect those conditions to continue throughout the rest of 2009 and potentially longer. The current weak economic conditions will likely result in weaker power and commodity markets, greater risk of defaults by our counterparties, weaker customer sales growth, particularly with respect to industrial sales, higher bad debt expense, higher financing costs, and possible impairment of goodwill and long-lived assets, among other things.
Future initiatives regarding greenhouse gas emissions and global warming are subject to active consideration in the U.S. Congress. In March 2009, the U.S. House of Representatives Committee on Energy and Commerce, Subcommittee on Energy and the Environment, issued a draft energy bill that included climate legislation. The climate legislation proposes establishing an economy-wide cap-and-trade program. The overarching goal of such legislation is to reduce greenhouse gas emissions to a level that is 20%
66
below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by the year 2050. The draft legislation also contains a renewable energy standard of 25% by the year 2025 and an energy efficiency mandate for electric and gas utilities, as well as other requirements. President Obama supports an economy-wide cap-and-trade greenhouse gas reduction program that would reduce emissions to 14% below 2005 levels by 2020 and to 80% below 2005 levels by 2050. President Obama has also indicated support for auctioning 100% of the emission allowances to be distributed under the legislation. However, recent statements from the Obama administration indicate a willingness to support some level of emission allowance allocation. Although we cannot predict the date of enactment or the requirements of any climate legislation, it is likely that some form of federal climate legislation will become law during the Obama administration. Potential impacts from proposed legislation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of allocating allowances, and provisions for cost containment measures.
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and non-rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by the Ameren and CILCORP holding companies are dependent on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below.
UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.
CIPS operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
Genco operates a non-rate-regulated electric generation business in Illinois and Missouri.
CILCO, a subsidiary of CILCORP (a holding company), operates a rate-regulated electric and natural gas transmission and distribution business and a non-rate-regulated electric generation business (through its subsidiary, AERG) in Illinois.
IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information helps readers to understand the impact of these factors on Ameren’s earnings per share. All references in this report to earnings per share are based on average diluted common shares outstanding during the applicable period. All tabular dollar amounts are in millions, unless otherwise indicated.
RESULTS OF OPERATIONS
Earnings Summary
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 affect the demand for our services. Our results are also affected by seasonal fluctuations: winter heating and summer cooling demands. The vast majority of Ameren’s revenues are subject to state or federal regulation. This regulation has a material impact on the price we charge for our services. Non-rate-regulated Generation sales are also subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, and oil for fuel in our operations. The prices for these commodities can fluctuate significantly due to the global economic and political environment, weather, supply and demand, and many other factors. We have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery businesses and purchased power cost recovery mechanisms for our Illinois electric delivery businesses. As part of the electric rate order issued by the MoPSC in January 2009, UE was granted permission to put in place a FAC, which was effective March 1, 2009. Fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems, the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.
Net income attributable to Ameren Corporation increased to $141 million, or 66 cents per share, in the first quarter of 2009, from $138 million, or 66 cents per share, in the first quarter of 2008. Net income attributable to Ameren Corporation in the first quarter of 2009 increased in the Illinois Regulated and Non-rate-regulated Generation segments by $9 million and $15 million, respectively, from the prior-year period, while net income attributable to Ameren Corporation in the Missouri Regulated segment declined by $31 million from the same period in 2008.
67
Earnings were favorably impacted in the first quarter of 2009 as compared with the same period in 2008 by:
higher electric and natural gas delivery service rates in the Illinois Regulated segment pursuant to the ICC consolidated rate order for CIPS, CILCO, and IP issued in September 2008 (12 cents per share);
favorable net unrealized MTM activity on energy-related transactions (9 cents per share);
higher electric rates in the Missouri Regulated segment pursuant to the MoPSC rate order issued in January 2009 (3 cents per share);
higher electric margins at our non-rate-regulated generation businesses (3 cents per share);
decreased bad debt expenses (2 cents per share); and
decreased plant operations and maintenance expense (2 cents per share).
Earnings were negatively impacted in the first quarter of 2009 as compared with the same period in 2008 by:
lower electric and gas margins at our rate-regulated businesses, excluding impacts of the rate increases noted above (17 cents per share);
the implementation of redesigned gas delivery service rates at the Ameren Illinois Utilities, which impacts quarterly earnings comparison but is not expected to have a material impact on annual margins (5 cents per share);
higher financing costs (4 cents per share);
reduced sales to Noranda due to a severe storm-related outage (3 cents per share); and
unfavorable weather conditions (estimated at 3 cents per share).
The cents per share information presented above is based on average shares outstanding in the first quarter of 2008.
Because it is a holding company, net income attributable to Ameren Corporation and cash flows are primarily generated by its principal subsidiaries: UE, CIPS, Genco, CILCORP and IP. The following table presents the contribution by Ameren’s principal subsidiaries to net income attributable to Ameren Corporation for the three months ended March 31, 2009 and 2008:
Net income (loss):
Other(c)
Net income attributable to Ameren Corporation
Below is a table of income statement components by segment for the three months ended March 31, 2009 and 2008:
Non-rate-
regulatedGeneration
Other /Intersegment
Three Months 2009:
Electric margin
Gas margin
Other revenues
Other income and (expenses)
Interest expense
Income taxes
Noncontrolling interest and preferred dividends
Net income (loss) attributable to Ameren Corporation
Three Months 2008:
68
regulated Generation
Margins
The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins for the three months ended March 31, 2009, compared with the same period in 2008. Electric margins are defined as electric revenues less fuel and purchased power costs. Gas margins are defined as gas revenues less gas purchased for resale. We consider electric, interchange, and gas margins useful measures to analyze the change in profitability of our electric and gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.
Electric revenue change:
Effect of weather (estimate)
Regulated rates:
Changes in base rates
FAC (over-recovery)
Illinois pass-through power costs
Non-rate-regulated Generation sales price changes
Off-system revenues
Illinois settlement agreement, net of reimbursement
Net MTM gains
Noranda sales
Generation output and other
Total electric revenue change
Fuel and purchased power change:
Fuel:
Generation and other
Net MTM gains (losses)
Price
Total fuel and purchased power change
Net change in electric margins
Gas margin change:
Gas rate increases
Illinois seasonal rate redesign
Net change in gas margins
Ameren’s electric margin increased by $8 million, or 1%, for the three months ended March 31, 2009, compared with the same period in 2008. The following items had a favorable impact on electric margin:
The reversal and deferral as regulatory assets of previously recorded UE net MTM losses on energy and fuel-related transactions of $42 million.
The effect of rate increases. The Ameren Illinois Utilities’ net electric rate increase, effective October 1, 2008, which increased electric margin by $25 million. The UE electric rate increase, effective March 1, 2009, which increased electric margin by $11 million.
69
Increased net MTM gains at the Non-rate-regulated Generation segment on energy transactions of $24 million, primarily related to nonqualifying hedges of changes in market prices for electricity.
The repricing of wholesale and retail electric power supply agreements and financial swaps settling at higher margins at Non-rate-regulated Generation.
The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $5 million.
Increased electric margin of $5 million related to the recovery of costs to administer the Ameren Illinois Utilities’ power supply responsibilities. This primarily relates to the increase in the Supply Cost Adjustment (SCA) factors approved in the 2008 ICC electric rate order.
The following items had an unfavorable impact on electric margin:
Fuel prices increased by 4%.
Off-system sales revenues at UE decreased by $21 million due primarily to a 23% decrease in realized sales prices.
Reduced sales to Noranda due to a severe storm-related outage, which lowered electric margin by $10 million. See Outlook for further information on the Noranda plant outage.
Unfavorable weather conditions, as evidenced by a 7% reduction in heating degree-days, which decreased electric margin by an estimated $6 million.
Excluding sales to Noranda, the impact of the economic slowdown, as evidenced by a 5% decrease in weather-normalized sales volumes, which decreased electric margin by $17 million. Specifically, combined commercial and industrial sales volumes decreased by 7%.
The implementation of the FAC at UE, effective March 1, 2009. UE’s base rates reflect costs set in the January 2009 MoPSC electric rate order for fuel and purchased power costs, net of off-system revenues. UE records 95% of the difference between actual net fuel costs and the base net fuel costs included in retail rates as an increase to or a reduction of electric revenues and defers such amount as a regulatory asset or liability to be recovered from or refunded to UE’s retail customers. In the first quarter of 2009, UE’s electric revenues were reduced by $13 million as a result of an over-recovery of fuel and purchased power costs, net of off-system sales.
Decreased power plant utilization due to lower demand and system transmission congestion. Ameren’s baseload coal-fired generating plants’ equivalent availability and capacity factors were 87% and 75%, respectively, in the first quarter of 2009 compared with 86% and 80%, respectively, in the first quarter of 2008.
Increased net MTM losses primarily at the Non-rate-regulated Generation segment on fuel-related transactions of $10 million, primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2009 through 2012.
Reduced Callaway nuclear plant availability due to a 12-day unplanned outage, which decreased electric margin by an estimated $7 million.
Ameren’s gas margin decreased by $15 million, or 10%, for the three months ended March 31, 2009, compared with the same period in 2008. The following items had an unfavorable impact on gas margin:
The implementation of redesigned seasonal gas delivery service rates at the Ameren Illinois Utilities, effective October 1, 2008, which decreased gas margin by $17 million. These redesigned delivery service rates have an impact on quarterly earnings comparisons but are not expected to materially impact annual margins.
Unfavorable weather conditions, as evidenced by a 7% reduction in heating degree-days, which decreased gas margin by an estimated $4 million.
A 12% decrease in weather-normalized sales volumes, which decreased gas margin by $9 million.
The following items had a favorable impact on gas margin:
The Ameren Illinois Utilities’ net gas delivery service rate increase, effective October 1, 2008, which increased gas margin by $13 million.
Increased transportation revenues, which increased gas margin by $2 million.
Missouri Regulated (UE)
UE’s electric margin decreased by $30 million, or 7%, for the three months ended March 31, 2009, compared with the same period in 2008. The following items had an unfavorable impact on electric margin:
Off-system sales revenues decreased by $21 million due primarily to a 23% decrease in realized sales prices.
Fuel prices increased by 8%.
The implementation of the FAC, effective March 1, 2009. UE’s base rates reflect costs set in the January 2009 MoPSC electric rate order for fuel and purchased power costs, net of off-system revenues. UE records 95% of the difference between actual net fuel costs and the base net fuel costs included in retail rates as an increase to or a reduction of electric revenues and defers such amount as a regulatory asset or liability to be recovered from or refunded to UE’s retail
70
customers. In the first quarter of 2009, UE’s electric revenues were reduced by $13 million as a result of an over-recovery of fuel and purchased power costs, net of off-system sales.
Unfavorable weather conditions, as evidenced by a 9% reduction in heating degree-days, which decreased electric margin by an estimated $5 million.
Excluding sales to Noranda, the impact of the economic slowdown, as evidenced by a 3% decrease in weather-normalized sales volumes, which decreased electric margin by $11 million.
The following items had a favorable impact on electric margin:
The reversal and deferral as regulatory assets of previously recorded net MTM losses on energy and fuel-related transactions of $42 million.
The electric rate increase, effective March 1, 2009, which increased electric margin by $11 million.
UE’s gas margin decreased by $1 million, or 4%, for the three months ended March 31, 2009, compared with the same period in 2008 primarily due to a 10% decrease in weather-normalized sales volumes.
Illinois Regulated
Illinois Regulated’s electric margin increased by $15 million, or 8%, for the three months ended March 31, 2009, compared with the same period in 2008. Illinois Regulated’s gas margin decreased by $14 million, or 11%, for the three months ended March 31, 2009, compared with the same period in 2008.
CIPS’ electric margin increased by $2 million, or 4%, for the three months ended March 31, 2009, compared with the same period in 2008. The following items had a favorable impact on electric margin:
The electric delivery service rate increase, effective October 1, 2008, which increased electric margin by $5 million.
The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $1 million.
Increased electric margin of $1 million related to the recovery of costs to administer power supply responsibilities. This primarily relates to the increase in the SCA factors as approved in the 2008 ICC electric rate order.
A 6% decrease in weather-normalized sales volumes, which decreased electric margin by $3 million.
Decreased transmission margin of $2 million.
Unfavorable weather conditions, as evidenced by an 8% decrease in heating degree-days, which decreased electric margin by an estimated $1 million.
CIPS’ gas margin decreased by $5 million, or 17%, for the three months ended March 31, 2009, compared with the same period in 2008. The following items had an unfavorable impact on gas margin:
The implementation of redesigned seasonal gas delivery service rates, effective October 1, 2008, which decreased gas margin by $4 million. The redesigned delivery service rates have an impact on quarterly earnings comparisons, but are not expected to materially impact annual margins.
Unfavorable weather conditions, as evidenced by an 8% decrease in heating degree-days, which decreased gas margin by an estimated $1 million.
A 14% decrease in weather-normalized sales volumes, which decreased gas margin by $4 million.
These unfavorable variances were partially offset by the gas delivery service rate increase, effective October 1, 2008, which increased gas margin by $3 million.
CILCO (Illinois Regulated)
The following table provides a reconciliation of CILCO’s change in electric margin by segment to CILCO’s total change in electric margin for the three months ended March 31, 2009, as compared with the same period in 2008:
Total change in electric margin
CILCO’s (Illinois Regulated) electric margin decreased by $5 million, or 13%, for the three months ended March 31, 2009, compared with the same period in 2008.
71
An 18% decrease in weather-normalized sales volumes, which decreased electric margin by $2 million.
The electric delivery service rate decrease, effective October 1, 2008, which decreased electric margin by $1 million.
These unfavorable variances were partially offset by an increase of $1 million related to the recovery of costs to administer power supply responsibilities. This primarily relates to the increase in the SCA factors as approved in the 2008 ICC electric rate order.
See Non-rate-regulated Generation below for an explanation of CILCO’s (AERG) change in electric margin for the three months ended March 31, 2009, as compared with the same period in 2008.
CILCO’s (Illinois Regulated) gas margin decreased by $8 million, or 22%, for the three months ended March 31, 2009, compared with the same period in 2008. The following items had an unfavorable impact on gas margins:
The implementation of redesigned seasonal gas delivery service rates, effective October 1, 2008, which decreased gas margin by $4 million. These redesigned delivery service rates have an impact on quarterly earnings comparisons but are not expected to materially impact annual margins.
The gas delivery service rate decrease, effective October 1, 2008, which decreased gas margin by $4 million.
Unfavorable weather conditions, as evidenced by a 4% reduction in heating degree-days, which decreased gas margin by an estimated $1 million.
IP’s electric margin increased by $18 million, or 21%, for the three months ended March 31, 2009, compared with the same period in 2008. The following items had a favorable impact on electric margin:
The electric delivery service rate increase, effective October 1, 2008, which increased electric margin by $21 million.
Increased electric margin of $3 million related to the recovery of costs to administer power supply responsibilities. This primarily relates to the increase in the SCA factors as approved in the 2008 ICC electric rate order.
Decreased transmission margin of $5 million, primarily related to ongoing MISO settlements.
A 5% decrease in weather-normalized sales volumes, which decreased electric margin by $1 million.
IP’s gas margin decreased by $1 million, or 2%, for the three months ended March 31, 2009, compared with the same period in 2008. The following items had an unfavorable impact on gas margin:
The implementation of redesigned seasonal gas delivery service rates, effective October 1, 2008, which decreased gas margin by $9 million. These redesigned delivery service rates have an impact on quarterly earnings comparisons but are not expected to materially impact annual margins.
Unfavorable weather conditions, as evidenced by a 6% decrease in heating degree-days, which decreased gas margin by an estimated $2 million.
A 10% decrease in weather-normalized sales volumes, which decreased gas margin by $4 million.
These unfavorable variances were partially offset by the gas delivery service rate increase, effective October 1, 2008, which increased gas margin by $14 million.
Non-rate-regulated Generation
Non-rate-regulated Generation’s electric margin increased by $13 million, or 5%, for the three months ended March 31, 2009, compared with the same period in 2008.
Genco’s electric margin increased by $4 million, or 3%, for the three months ended March 31, 2009, compared with the same period in 2008. The following items had a favorable impact on electric margin:
Increased revenues allocated to Genco under its power supply agreement (Genco PSA) with Marketing Company. Revenues from the Genco PSA increased due to financial swaps settling at higher margins and new higher-priced wholesale and retail electric power supply agreements, partially offset by lower reimbursable expenses in accordance with the Genco PSA.
Lower emission allowance costs of $3 million.
Gains on the sales of excess gas normally used in generation, which increased electric margin by $2 million.
72
The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $2 million.
Decreased power plant utilization. Genco’s baseload coal-fired generating plants’ equivalent availability factor was 87% in the first quarter of 2009 compared with 86% in 2008. However, the average capacity factor was 62% in 2009, compared with 79% in 2008, because of lower prices and transmission congestion.
Fuel prices increased by 3%.
Increased net MTM losses on fuel-related transactions of $6 million, primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2009 through 2012.
Lower affiliated replacement power insurance recoveries of $6 million.
AERG’s electric margin increased by $17 million, or 35%, for the three months ended March 31, 2009, compared with the same period in 2008. The following items had a favorable impact on electric margin:
Increased revenues allocated to AERG under its power supply agreement (AERG PSA) with Marketing Company. Revenues from the AERG PSA increased due to financial swaps settling at higher margins and the new higher priced wholesale and retail electric power supply agreements.
A $2 million decrease in oil consumption resulting from fewer plant start-ups in 2009.
Decreased power plant availability due, in part, to a planned plant outage. AERG’s baseload coal-fired generating plants’ equivalent availability and average capacity factors were 63% and 58%, respectively, in the first quarter of 2009, compared with 77% and 72%, respectively, in the first quarter of 2008.
Increased net MTM losses on fuel-related transactions of $1 million, primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2009 through 2012.
EEI’s electric margin decreased by $45 million, or 58%, for the three months ended March 31, 2009, compared with the same period in 2008. The following items had an unfavorable impact on electric margin:
The average sales price for power decreased by 36%.
Fuel prices increased by 18% due to an 88% increase in transportation costs.
Increased net MTM losses on fuel-related transactions of $2 million, primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2009 through 2012.
These unfavorable variances were partially offset by net MTM gains on energy transactions of $2 million, primarily related to nonqualifying hedges of changes in market prices for electricity.
Marketing Company
A decrease in market prices during the first quarter of 2009 resulted in nonaffiliated MTM gains on energy transactions of $22 million for the three months ended March 31, 2009. These unrealized gains primarily related to nonqualifying hedges of changes in market prices for electricity.
Operating Expenses and Other Statement of Income Items
Other Operations and Maintenance
Other operations and maintenance expenses decreased $9 million in the first quarter of 2009 compared with the first quarter of 2008, primarily because of reductions in bad debt expense of $7 million, injuries and damages expenses of $4 million, plant maintenance costs of $4 million and employee benefit costs of $3 million. Higher labor costs of $10 million reduced the benefit of these items.
Variations in other operations and maintenance expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months ended March 31, 2009, compared with the same period in 2008, were as follows:
UE’s other operations and maintenance expenses were comparable between periods. Storm repair expenditures increased $8 million over the prior-year period. Employee benefit costs and injuries and damages expenses each decreased $2 million, along with less significant decreases in various other operations and maintenance expenses.
73
Other operations and maintenance expenses decreased $11 million in the Illinois Regulated segment in the three months ended March 31, 2009, compared with the same period in 2008.
Other operations and maintenance expenses decreased $7 million in the first quarter of 2009, compared with the first quarter of 2008, primarily because of lower storm repair expenditures of $2 million and a reduction in bad debt expense of $3 million.
Other operations and maintenance expenses increased $16 million in the three months ended March 31, 2009, compared with the same period in 2008, primarily because of higher labor costs of $12 million and increased employee benefit costs of $4 million. These increases were primarily a result of work performed on behalf of CIPS and CILCO as discussed below.
At the beginning of 2009, approximately 570 employees were transferred from Ameren Services to CILCO (Illinois Regulated), which resulted in an increase in other operations and maintenance expenses at CILCO (Illinois Regulated) during the first quarter of 2009, as noted below. These CILCO (Illinois Regulated) employees also provide support services to CIPS and IP. CILCO (Illinois Regulated) records reimbursements from CIPS and IP for work performed by its employees on their behalf as Operating Revenues - Other on its statement of income, which increased $17 million in the first quarter of 2009. Intercompany revenue and expenses associated with these transactions are eliminated within the Illinois Regulated segment. See Note 8 - Related Party Transactions to our financial statements under Part I, Item 1, of this report for further information on CILCO support services.
IP’s other operations and maintenance expenses decreased $4 million in the first quarter of 2009 compared with the first quarter of 2008, primarily because of reduced bad debt expense.
Other operations and maintenance expenses were comparable in the first quarter of 2009 with the same period in 2008 in the Non-rate-regulated Generation segment and at Genco, CILCO (AERG), CILCORP (parent company only), and EEI.
Goodwill Impairment Loss
During the first quarter of 2009, CILCORP recognized a goodwill impairment charge of $462 million. See Note 14 - Goodwill Impairment to our financial statements under Part I, Item 1, of this report for additional information.
Depreciation and Amortization
Ameren’s depreciation and amortization expenses increased $5 million in the first quarter of 2009, compared with the same period in 2008, because of items noted below at the Ameren Companies.
Variations in depreciation and amortization expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months ended March 31, 2009, compared with the same period in 2008, were as follows:
Depreciation and amortization expenses increased $5 million in the first quarter of 2009, compared with the same period in 2008, primarily because of capital additions.
Depreciation and amortization expenses decreased $2 million in the three months ended March 31, 2009, compared with the same period in 2008, in the Illinois Regulated segment. As part of the consolidated electric and natural gas rate order issued by the ICC in September 2008, the ICC changed plant asset useful lives, effective October 1, 2008, which resulted in reductions in depreciation expense at CIPS and CILCO (Illinois Regulated) and an increase in depreciation expense at IP. Capital additions mitigated the benefit of the rate order at CIPS and CILCO (Illinois Regulated) and further increased depreciation and amortization expenses at IP. The net effect of the above items was a reduction in depreciation and amortization expenses at CILCO (Illinois Regulated) of $6 million and an increase at IP of $4 million. Depreciation and amortization expenses at CIPS were comparable between periods.
74
Depreciation and amortization expenses were comparable in the Non-rate-regulated Generation segment and at Genco, CILCO (AERG), CILCORP (parent company only), and EEI between periods.
Taxes Other Than Income Taxes
Ameren’s taxes other than income taxes decreased $3 million in the first quarter of 2009, compared with the same period in 2008, primarily because of lower gross receipts taxes, offset in part by higher property taxes.
Variations in taxes other than income taxes in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months ended March 31, 2009, compared with the same period in 2008, were as follows:
Taxes other than income taxes increased $2 million at UE in the first quarter of 2009, compared with the same period in 2008, primarily because of higher property taxes.
Taxes other than income taxes decreased $4 million in the Illinois Regulated segment in the three months ended March 31, 2009, compared with the same period in 2008.
CIPS & IP
Taxes other than income taxes decreased $2 million at both CIPS and IP in the first quarter of 2009, compared with the same period in 2008, primarily because of reduced gross receipts taxes.
Taxes other than income taxes at CILCO (Illinois Regulated) were comparable between periods.
Taxes other than income taxes were comparable in the three months ended March 31, 2009, with the same period in 2008 in the Non-rate-regulated Generation segment and for Genco, CILCO (AERG), CILCORP (parent company only) and EEI.
Other Income and Expenses
Other income and expenses decreased $3 million in the first quarter of 2009, compared with the same period in 2008, primarily because of lower interest income.
Variations in other income and expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months ended March 31, 2009, compared with the same period in 2008, were as follows:
Other income and expenses at UE were comparable between periods.
Other income and expenses in the Illinois Regulated segment decreased $3 million in the first quarter of 2009, compared with the same period in 2008, primarily because of lower interest income at IP. Other income and expenses at CIPS and CILCO (Illinois Regulated) were comparable between periods.
Other income and expenses in the Non-rate-regulated Generation segment and at Genco, CILCO (AERG), CILCORP (parent company only) and EEI were comparable in the three months ended March 31, 2009, with the same period in 2008.
Ameren’s interest expense increased $18 million in the first quarter of 2009 compared with the first quarter of 2008, because of items noted below at the Ameren Companies.
Variations in interest expense in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months ended March 31, 2009, compared with the same period in 2008, were as follows:
Interest expense increased $12 million in the three months ended March 31, 2009, compared with the same period in 2008. Interest charges associated with the issuance of senior secured notes of $450 million and $250 million in June 2008 and April 2008, respectively, increased interest expense over the first quarter of 2008. The senior secured notes were issued to refinance
75
auction-rate environmental improvement revenue refunding bonds, to fund the maturity of $148 million of first mortgage bonds, and to reduce short-term borrowings. Additionally, interest expense increased over the first quarter of 2008 because of favorable income tax settlements in the prior-year period.
Interest expense increased $6 million in the Illinois Regulated segment in the first three months of 2009, as compared with the same period in 2008.
Interest expense was comparable between periods.
Interest expense increased $2 million in the first quarter of 2009 compared with the first quarter of 2008, primarily because of the issuance of senior secured notes of $150 million in December 2008.
Interest expense increased $2 million in the first quarter of 2009 compared with the first quarter of 2008, primarily because of the issuance of senior secured notes of $400 million and $337 million at IP in October 2008 and April 2008, respectively. The proceeds from the senior secured notes were used to refinance auction-rate pollution control revenue refunding bonds and to reduce short-term borrowings. The October 2008 senior secured notes were at a higher interest rate than the refinanced short-term debt.
Interest expense increased $4 million in the Non-rate-regulated Generation segment in the first three months of 2009, as compared with the same period in 2008.
Interest expense increased $7 million in the first quarter of 2009 compared with the first quarter of 2008, primarily because of the issuance of $300 million of senior unsecured notes at Genco in April 2008. The proceeds from these notes were used to fund capital expenditures, repay short-term debt, and for general corporate purposes. Additionally, interest expense increased over the first quarter of 2008 because of favorable income tax settlements in the prior-year period.
CILCO (AERG), CILCORP (parent company only), and EEI
Interest expense at CILCO (AERG), CILCORP (parent company only), and EEI was comparable between periods.
Ameren’s effective tax rate in the first quarter of 2009 was lower than the effective tax rate for the same period in the prior year, due to variations discussed below.
Variations in effective tax rates for Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months ended March 31, 2009, compared with the same period in 2008 were as follows:
The effective tax rate for the first quarter of 2009 was lower than the effective tax rate for the first quarter of 2008, primarily because of higher favorable net amortization of property-related regulatory assets and liabilities along with the impact of investment tax credit amortization and permanent items on lower pretax book income in the first quarter of 2009 when compared to the first quarter of 2008.
The effective tax rate for the first quarter of 2009 was higher than the effective tax rate for the same period in 2008 in the Illinois Regulated segment because of items detailed below.
The effective tax rate for the first quarter of 2009 was higher than the effective tax rate for the same period in 2008, primarily because of the impact of net amortization of property-related regulatory assets and liabilities, investment tax credit amortization and permanent items on higher pretax book income in the first quarter of 2009 as compared with the first quarter of 2008.
The effective tax rate for the first quarter of 2009 was lower than the effective tax rate for the first quarter of 2008, primarily because of the impact of permanent items, net amortization of property-related regulatory assets and liabilities, and amortization of investment tax credit on lower pretax book income during the current-year period as compared with the same period in 2008.
76
The effective tax rate for the first quarter of 2009 was lower than the effective tax rate for the same period in 2008, primarily because of the impact of permanent items and the net amortization of property-related regulatory assets and liabilities on higher pretax book income during the current-year period as compared with the same period in 2008.
The effective tax rate for the first quarter of 2009 was lower than the effective tax rate for the first quarter of 2008 in the Non-rate-regulated Generation segment, because of items detailed below.
The effective tax rate for the first quarter of 2009 was lower than the effective tax rate for the same period in 2008, primarily because of the increased impact of production activity deductions and changes to reserves for uncertain tax positions during the current-year period.
The effective tax rate for the first quarter of 2009 was lower than the effective tax rate for the first quarter of 2008, primarily because of changes to reserves for uncertain tax positions, offset by a decreased impact of production activity deductions when compared to the year-ago period.
The effective tax rate was comparable between periods.
CILCORP (parent company only)
The effective tax rate for the first quarter of 2009 was lower than the effective tax rate for the same period in 2008, primarily due to the effect of the goodwill impairment loss of $462 million, which was a permanent item, on a pretax book loss. The amount of the goodwill impairment loss that was assigned to CILCORP’s Illinois Regulated and Non-rate-regulated Generation business segments was $117 million and $345 million, respectively. As a result of the impairment loss, the effective tax rates for the first quarter of 2009 for CILCORP’s Illinois Regulated and Non-rate-regulated Generation business segments were also lower than the effective tax rates in the same period in 2008.
LIQUIDITY AND CAPITAL RESOURCES
The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO (Illinois Regulated) and IP) continue to be the principal source of cash from operating activities for Ameren and its rate-regulated subsidiaries. A 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 for Ameren, UE, CIPS, CILCO (Illinois Regulated) and IP. For operating cash flows, Genco and AERG rely on power sales to Marketing Company, which sold power through the September 2006 Illinois power procurement auction, financial contracts that were part of the Illinois electric settlement agreement and the 2008 Illinois RFP process for energy and capacity that was used pursuant to the Illinois electric settlement agreement. Marketing Company is also selling power through other primarily market-based contracts with wholesale and retail customers. In addition to cash flows from operating activities, the Ameren Companies use available cash, credit facilities, money pool or other short-term borrowings from affiliates to support normal operations and other temporary capital requirements. The use of operating cash flows and short-term borrowings to fund capital expenditures and other investments may periodically result in a working capital deficit, as was the case at March 31, 2009, for Ameren, CIPS, Genco, CILCORP, and CILCO. The Ameren Companies may reduce their short-term borrowings with cash from operations or discretionarily with long-term borrowings, or in the case of Ameren subsidiaries, with equity infusions from Ameren. The Ameren Companies expect to incur significant capital expenditures over the next five years as they comply with environmental regulations and make significant investments in their electric and gas utility infrastructure to improve overall system reliability. Ameren intends to finance those capital expenditures and investments with a blend of equity and debt so that it maintains a capital structure in its rate-regulated businesses containing approximately 50% to 55% equity. Consequently, we expect to make equity issuances in the future consistent with this objective, as well as to address any unanticipated events, should the need arise. We plan to implement our long-term financing plans for debt, equity or equity-linked securities in order to appropriately finance our operations, meet scheduled debt maturities and maintain financial strength and flexibility.
The global capital and credit markets experienced extreme volatility and disruption in 2008, and continue to experience volatility and disruption in 2009. See Outlook for a discussion of the implications of this volatility and disruption for the Ameren Companies and our plans to address these issues.
77
The following table presents net cash provided by (used in) operating, investing and financing activities for the three months ended March 31, 2009 and 2008:
Net Cash Provided By
(Used In ) Operating Activities
Net Cash (Used In)
Investing Activities
(Used In) Financing Activities
Cash Flows from Operating Activities
Ameren’s cash from operating activities increased in the first three months of 2009 compared with the first three months of 2008. The increase is primarily due to an $88 million decrease in cash payments related to the December 2005 Taum Sauk incident, net of insurance recoveries and a decrease in income tax payments, net of refunds, of $36 million. Other factors contributing to the increase in operating cash flow during the first quarter of 2009, compared with the same period in 2008, included an increase in electric costs over-recovered from Illinois customers under cost recovery mechanisms, an increase in gas costs over-recovered from customers under the PGA, a reduction of net levels of collateral posted with suppliers of $35 million, a decrease in interest payments of $12 million, and a $7 million increase in customer advances for construction. Partially offsetting the increase in cash flow from operations during the first three months of 2009, compared to the same period in 2008, was an increase in annual incentive compensation payments, the impact of the Illinois electric settlement agreement, which reduced cash flow from operations by $17 million, and an increase in cash payments for storm restoration of $5 million.
UE’s cash from operating activities increased in the first three months of 2009 compared with the first three months of 2008. The increase was primarily due to a decrease in income tax payments, net of refunds, of $90 million and an $88 million decrease in cash payments related to the December 2005 Taum Sauk incident, net of insurance recoveries. Other factors contributing to the increase in operating cash flow during the first quarter of 2009, compared with the same period in 2008, included a reduction in inventories in the normal course of business and an increase in gas costs over-recovered from customers under the PGA. Partially offsetting the increase in cash flow from operations during the first three months of 2009, compared to the same period in 2008, was the collection in 2008 of an $85 million affiliate receivable, lower margins as discussed in Results of Operations, a $14 million increase in interest payments, a $6 million increase in storm restoration costs, and higher net levels of collateral posted with suppliers of $6 million.
CIPS’ cash from operating activities increased in the first three months of 2009 compared with the first three months of 2008. The increase is primarily a result of a reduction in receivables caused by more cash collected in 2009 from 2008 receivables, due to colder weather in the fourth quarter of 2008, compared with 2008 collections from 2007. Other factors contributing to the increase in operating cash flow during the first quarter of 2009, compared with the same period in 2008, included an increase in electric costs over-recovered from customers and a decrease in interest payments of $5 million. Partially offsetting the increase in cash flow from operations during the first three months of 2009, compared to the same period in 2008, were higher net levels of collateral posted with suppliers of $13 million and an increase in income tax payments, net of refunds, of $10 million. Also, the impact of the Illinois electric settlement agreement reduced CIPS’ cash from operations by $9 million for the first three months of 2009 compared with the same period in 2008.
Genco’s cash from operating activities increased in the first three months of 2009 compared with the first three months of 2008. Factors contributing to the increase included higher margins as discussed in Results of Operations and a $5 million reduction in funding required by the Illinois electric settlement agreement. Other increases in cash flow from operations were due to fluctuations in working capital in the normal course of business. Partially offsetting the increase in cash flow from operations during the first three months of 2009, compared to the same period in 2008, was an increase in income tax payments, net of refunds, of $11 million.
CILCORP’s and CILCO’s cash from operating activities decreased in the first three months of 2009 compared with the first three months of 2008. The decrease was a result of an increase in income tax payments, net of refunds, of $25 million for CILCORP and $29 million for CILCO, a decrease in electric costs over-recovered from customers, a higher net level of collateral posted with suppliers of $28 million, and an increase in annual incentive compensation payments. On January 1, 2009, approximately 570 Ameren Services employees who provide support services to the Ameren Illinois Utilities were transferred to CILCO. As CILCO
78
employees, they provide services to CIPS and IP as well as to CILCO. The timing of related-party payments for services provided to CIPS and IP resulted in a reduction of operating cash flow of $6 million. Also, the impact of the Illinois electric settlement agreement reduced CILCORP’s cash from operations by $5 million for the first three months of 2009 compared with the same period in 2008. Partially offsetting the decrease in cash flow from operations during the first three months of 2009, compared to the same period in 2008, was an increase in gas costs over-recovered from customers under the PGA, a decrease in interest payments of $7 million for CILCORP and $5 million for CILCO, and a reduction in receivables caused by more cash collected in 2009 from 2008 receivables, due to colder weather in the fourth quarter of 2008, compared with 2008 collections from 2007.
IP’s cash from operating activities increased in the first three months of 2009 compared with the first three months of 2008. The increase was primarily a result of a reduction in receivables caused by more cash collected in 2009 from 2008 receivables, due to colder weather in the fourth quarter of 2008, compared with 2008 collections from 2007. Other factors contributing to the increase in operating cash flow during the first quarter of 2009, compared with the same period in 2008, included an increase in gas costs over-recovered from customers under the PGA and a decrease in interest payments of $10 million. Partially offsetting the increase in cash flow from operations during the first three months of 2009, compared to the same period in 2008, included higher net levels of collateral posted with suppliers of $37 million and an increase in income tax payments, net of refunds, of $19 million. Also, the impact of the Illinois electric settlement agreement reduced IP’s cash from operations by $10 million for the first three months of 2009 compared with the same period in 2008.
Cash Flows from Investing Activities
Ameren’s cash used for investing activities decreased during the first three months of 2009 compared with the first three months of 2008. The decrease was primarily driven by a $99 million decrease in nuclear fuel expenditures. Partially offsetting this decrease was a slight increase in net cash used for capital expenditures as a result of increased storm restoration costs.
UE’s cash used in investing activities decreased during the three months ended March 31, 2009, compared with the same period in 2008, principally because of a $99 million decrease in nuclear fuel expenditures. Partially offsetting this decrease was a $17 million increase in capital expenditures primarily as a result of increased storm restoration costs.
CIPS’ cash used in investing activities during the first three months of 2009 decreased compared with the same period in 2008. During both periods, cash was used for capital expenditures, primarily for reliability improvements of the transmission and distribution system.
Genco’s cash used in investing activities increased in the first three months of 2009 compared with the same period in 2008, principally because of an $11 million increase in capital expenditures due to a power plant scrubber project.
CILCORP’s and CILCO’s cash used in investing activities decreased in the three months ended March 31, 2009, compared with the same period in 2008, primarily as a result of a $21 million decrease in capital expenditures, due to reduced spending related to a power plant scrubber project at AERG.
IP’s cash used in investing activities increased in the first three months of 2009, compared with the same period in 2008, principally as a result of a $12 million increase in net money pool advances. Capital expenditures also increased by $2 million in the first three months of 2009 from the year-ago period.
See Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for a discussion of future environmental capital expenditure estimates.
We continually review our generation portfolio and expected power needs. As a result, we could modify our plan for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other things. In addition, Ameren and Genco are currently considering divestiture of some of Genco’s smaller non-rate-regulated generating units. Any changes that we may plan to make for future generating needs could result in significant capital expenditures or losses being incurred, which could be material.
Cash Flows from Financing Activities
Ameren’s cash provided by financing activities increased in the first three months of 2009 compared with the first three months of 2008. During the three months ended March 31, 2009, UE issued $350 million of senior secured notes and used the proceeds to reduce net short-term borrowings. Comparatively, during the first three months of 2008, Ameren had no issuances of long-term debt and net short-term borrowings of $145 million. Also, benefiting cash flow from financing activities for the three months ended March 31, 2009, compared with the year-ago period, was a $51 million decrease in dividends paid on Ameren common stock resulting from the reduction of the quarterly dividend rate.
79
UE’s net cash provided by financing activities increased in the first three months of 2009, compared with the same period of the prior year. During the three months ended March 31, 2009, UE issued $350 million of senior secured notes and used the proceeds to reduce short-term debt. Comparatively, during the three months ended March 31, 2008, UE had net short-term borrowings of $126 million that were used to fund working capital requirements. Additionally, UE reduced its borrowings under an intercompany borrowing arrangement with Ameren during the three months ended March 31, 2009, compared with borrowings from Ameren during the three months ended March 31, 2008.
CIPS’ net cash used in financing activities increased during the three months ended March 31, 2009, compared with the first three months of 2008. This change was a result of CIPS using existing cash and increased borrowings from the money pool to fund a net reduction in short-term debt.
Genco’s net cash used in financing activities increased during the three months ended March 31, 2009 compared with the year-ago period. This change was the result of a net $21 million reduction in money pool borrowings. Additionally, during the first quarter of 2009, Genco had no short-term debt activity compared with $50 million of net short-term debt borrowings in the first quarter of 2008 and paid no common stock dividends in the first quarter of 2009 compared with $24 million of common stock dividends paid in the first quarter of 2008.
CILCORP’s and CILCO’s cash provided by financing activities increased during the three months ended March 31, 2009, compared with the same period in 2008. This increase is primarily the result of CILCORP’s and CILCO’s increased intercompany and money pool borrowings that were used to reduce their short-term borrowings during the three months ended March 31, 2009, compared with the 2008 period. An $11 million capital contribution received by CILCO in the first quarter of 2009 from CILCORP resulted in a positive impact on cash flows at CILCO for the first three months of 2009.
IP received a $58 million capital contribution from Ameren during the first quarter of 2009. This contribution was the primary source of cash provided by financing activities for the three months ended March 31, 2009. Comparatively, during the first quarter of 2008, IP had net cash used in financing activities as the result of net repayments of short-term borrowings, funding of current debt maturities, and funding of common stock dividends.
Short-term Borrowings and Liquidity
External short-term borrowings typically consist of drawings under committed bank credit facilities. See Note 3 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report for additional information on credit facilities, short-term borrowing activity, relevant interest rates, and borrowings under Ameren’s utility and non-state-regulated subsidiary money pool arrangements.
The following table presents the various committed bank credit facilities of the Ameren Companies and AERG, and their availability, as of March 31, 2009:
Ameren, UE and Genco:
Multiyear revolving(b)
CIPS, CILCORP, CILCO, IP and AERG:
2007 Multiyear revolving(c)
2006 Multiyear revolving(d)
80
On September 15, 2008, Lehman filed for protection under Chapter 11 of the federal Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New York. As of March 31, 2009, Lehman Brothers Bank, FSB, a subsidiary of Lehman, had lending commitments of $100 million and $21 million under the $1.15 billion credit facility and the 2006 $500 million credit facility, respectively. At this time, we do not know if Lehman Brothers Bank, FSB will seek to assign to other parties any of its commitments under our credit facilities. Assuming Lehman Brothers Bank, FSB does not fund its pro-rata share of funding requests under these two facilities, and such participations are not assigned or otherwise transferred to other lenders, total amounts accessible by the Ameren Companies and AERG will be limited to amounts not less than $1.05 billion under the $1.15 billion credit facility and $479 million under the 2006 $500 million credit facility. The Ameren Companies and AERG do not believe that the potential reduction in available capacity under the credit facilities, if Lehman Brothers Bank, FSB does not fund its commitments, will have a material impact on their liquidity.
On June 25, 2008, Ameren entered into a $300 million term loan agreement due June 24, 2009, which was fully drawn on June 26, 2008. See Note 3 - Short-term Borrowings and Liquidity to our financial statements under Part 1, Item 1, of this report for additional information.
On January 21, 2009, Ameren entered into a $20 million term loan agreement due January 20, 2010, which was fully drawn on January 21, 2009. See Note 3 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item I, of this report for additional information.
In addition to committed credit facilities, a further source of liquidity for the Ameren Companies from time to time is available cash and cash equivalents. At March 31, 2009, Ameren (on a consolidated basis), UE, CIPS, Genco, CILCORP (on a consolidated basis), CILCO, and IP had $304 million, $27 million, less than $1 million, $2 million, $35 million, $35 million, and $179 million, respectively, of cash and cash equivalents.
The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by FERC under the Federal Power Act. In March 2008, FERC issued an order authorizing the issuance of short-term debt securities subject to the following limits on outstanding balances: UE - $1 billion, CIPS - $250 million, and CILCO - $250 million. The authorization was effective as of April 1, 2008, and terminates on March 31, 2010. IP has unlimited short-term debt authorization from FERC.
Genco was authorized by FERC in its March 2008 order to have up to $500 million of short-term debt outstanding at any time. AERG and EEI have unlimited short-term debt authorization from FERC.
The issuance of short-term debt securities by Ameren and CILCORP (parent) is not subject to approval by any regulatory body.
The Ameren Companies continually evaluate the adequacy and appropriateness of their credit arrangements given changing business conditions. When business conditions warrant, changes may be made to existing credit agreements or other short-term borrowing arrangements.
Long-term Debt and Equity
The following table presents the issuances of common stock and the issuances, redemptions, repurchases and maturities of long-term debt (net of any issuance discounts and including any redemption premiums) for the three months ended March 31, 2009 and 2008, for the Ameren Companies. For additional information related to the terms and uses of these issuances and the sources of funds and terms for the redemptions, see Note 4 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report.
Month Issued, Redeemed,
Repurchased or Matured
Issuances
8.45% Senior secured notes due 2039
Total Ameren long-term debt issuances
Ameren:
DRPlus and 401(k)
Total common stock issuances
Total Ameren long-term debt and common stock issuances
Redemptions, Repurchases and Maturities
Note payable to IP SPT:
5.65% Series due 2008
Total Ameren long-term debt redemptions, repurchases and maturities
81
The following table presents information with respect to the Form S-3 shelf registration statements filed and effective for certain Ameren Companies as of March 31, 2009:
Effective
Date
Authorized
Amount
UE(b)
CIPS(a)
Genco(a)
CILCO(a)
IP(a)
In July 2008, Ameren filed a Form S-3 registration statement with the SEC authorizing the offering of six million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions. Ameren is currently selling newly issued shares of its common stock under DRPlus.
Ameren is also currently selling newly issued shares of its common stock under its 401(k) plan pursuant to an effective SEC Form S-8 registration statement. Under DRPlus and its 401(k) plan, Ameren issued a total of 1.1 million new shares of common stock valued at $28 million in the three months ended March 31, 2009.
Ameren, UE, CIPS, Genco, CILCO and IP may sell all or a portion of the securities registered under their effective registration statements if market conditions and capital requirements warrant such a sale. Any offer and sale will be made only by means of a prospectus that meets the requirements of the Securities Act of 1933 and the rules and regulations thereunder.
See Note 4 - Short-term Borrowings and Liquidity and Note 5 - Long-term Debt and Equity Financings in the Form 10-K for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our bank credit and term loan facilities and in certain of the Ameren Companies’ indenture agreements and articles of incorporation.
At March 31, 2009, the Ameren Companies were in compliance with their credit facility, term loan agreements, indenture, and articles of incorporation provisions and covenants.
We consider access to short-term and long-term capital markets a significant source of funding for capital requirements not satisfied by our operating cash flows. Inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing our current operating performance, liquidity, and credit ratings (see Credit Ratings below), 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 or make access to the capital markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital markets.
Ameren paid to its stockholders common stock dividends totaling $82 million, or 38.5 cents per share, during the first three months of 2009 (2008 - $133 million or 63.5 cents per share). On April 28, 2009, Ameren’s board of directors declared a quarterly common stock dividend of 38.5 cents per share payable on June 30, 2009, to stockholders of record on June 10, 2009.
See Note 4 - Short-term Borrowings and Liquidity and Note 5 - Long-term Debt and Equity Financings in the Form 10-K for a discussion of covenants and provisions contained in certain of the Ameren Companies’ financial agreements and articles of incorporation that would restrict the Ameren Companies’ payment of dividends in certain circumstances. At March 31, 2009, except as discussed below with respect to the 2007 $500 million credit facility and the 2006 $500 million credit facility, none of these circumstances existed at the Ameren Companies and, as a result, they were allowed to pay dividends.
The 2007 $500 million credit facility and 2006 $500 million credit facility limit the amount of CIPS, CILCORP, CILCO and IP common and preferred stock dividend payments to $10 million per year each if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have received a below investment-grade credit rating from either Moody’s or S&P. With respect to AERG, which currently is not rated by Moody’s or S&P, the common and preferred stock dividend restriction will not apply if its ratio of consolidated total debt to consolidated operating cash flow, pursuant to a calculation defined in the facilities, is less than or equal to 3.0 to 1.0. CILCORP’s senior unsecured credit ratings from Moody’s and S&P are below investment-grade, causing it to be subject to this dividend payment limitation. As of March 31, 2009, AERG failed to meet the debt-to-operating cash flow ratio test in the 2007 and 2006 $500 million credit facilities. AERG’s ability to pay dividends is therefore limited to a maximum of $10 million per fiscal year. CIPS, CILCO and IP are not currently limited in their
82
dividend payments by this provision of the 2007 or 2006 $500 million credit facilities. Ameren’s access to dividends from CILCO and AERG is currently limited by dividend restrictions at CILCORP.
The following table presents common stock dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents for the three months ended March 31, 2009 and 2008.
Nonregistrants
Dividends paid by Ameren
Contractual Obligations
For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7 and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K, and Other Obligations in Note 9 - Commitments and Contingencies under Part I, Item 1, of this report. See Note 12 - Retirement Benefits to our financial statements under Part I, Item 1, of this report for information regarding expected minimum funding levels for our pension plan.
Subsequent to December 31, 2008, obligations related to the procurement of coal, natural gas, and electricity materially changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $5,468 million, $2,548 million, $335 million, $599 million, $878 million, $878 million and $547 million, respectively. Total other obligations, including the amount of unrecognized tax benefits, at March 31, 2009, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $6,713 million, $3,435 million, $361 million, $599 million, $945 million, $945 million and $679 million, respectively.
As a result of the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over a four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco and $28 million from AERG. Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues, during the quarter ended March 31, 2009, of $6 million, $1 million, less than $1 million, $1 million, $2 million, and $1 million, respectively, (quarter ended March 31, 2008 - $11 million, $2 million, $1 million, $2 million, $4 million, and $2 million, respectively) under the terms of the Illinois electric settlement agreement. At March 31, 2009, Ameren, CIPS, CILCO (Illinois Regulated) and IP had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $6 million, $2 million, $1 million and $3 million, respectively. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for additional information regarding the Illinois electric settlement agreement.
Credit Ratings
The following table presents the principal credit ratings of the Ameren Companies by Moody’s, S&P and Fitch effective on the date of this report:
Issuer/corporate credit rating
Senior unsecured debt
Secured debt
Moody’s Ratings Actions
On January 29, 2009, Moody’s affirmed the ratings of CIPS, CILCORP, CILCO and IP and changed their rating outlooks to stable from positive. According to Moody’s, the change in the rating outlooks of these four companies was based on the near-term expiration of the 2007 and 2006 $500 million credit facilities in January 2010 and related liquidity concerns. Moody’s also on January 29, 2009, affirmed the ratings of Ameren and UE with a stable outlook based on the January 2009 MoPSC electric rate order approving a rate increase and a FAC for UE.
On February 16, 2009, Moody’s affirmed the ratings of Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP with a stable outlook. The affirmation reflects Moody’s view that Ameren’s announcement to reduce its common stock dividend by 39% is a conservative, prudent, and credit positive action that will conserve cash and support financial coverage metrics. Moody’s stated that the more conservative dividend payout should also help facilitate the renewal of Ameren Companies’ credit facilities that expire in 2010. They stated the dividend reduction should continue to reduce reliance on the credit facilities going forward and will likely be viewed favorably by lenders considering renewing or entering into new facilities with Ameren and its subsidiaries, which is
83
important considering currently constrained credit market conditions. According to Moody’s, the stable outlook on Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP reflects recently constructive rate case outcomes at UE, CIPS, CILCO and IP, including the approval of a FAC at UE; the improving regulatory environments for investor-owned utilities in Illinois and Missouri; and Moody’s expectation that financial and cash flow coverage metrics should remain adequate to maintain current rating levels. In addition, Moody’s noted that the recent dividend reduction is supportive of the stable ratings outlooks and provides Ameren and its subsidiaries additional cushion at current rating levels.
S&P Ratings Actions
On February 25, 2009, S&P stated that it viewed the reduction in Ameren’s common stock dividend as credit supportive. S&P did not make any changes in Ameren’s or its subsidiaries’ credit ratings or outlooks as a result of this action. S&P raised the business profile of UE to “excellent” from “strong” to reflect the recent electric rate order issued by the MoPSC, which S&P viewed as constructive. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for a discussion of the rate order issued by the MoPSC on January 27, 2009. S&P lowered the business profile of CILCO to “satisfactory” from “strong” reflecting S&P’s concerns regarding large capital expenditures needed to meet environmental compliance standards, while relying on falling market prices, due to the economic recession, for recovery.
Fitch Ratings Actions
On February 17, 2009, Fitch stated that the reduction in Ameren’s common stock dividend and other cost-cutting measures will be favorable to bondholders and credit quality. Fitch did not make any changes in Ameren’s or its subsidiaries’ ratings or outlooks as a result of this action.
On March 9, 2009, Fitch lowered the credit ratings of UE by one notch as follows: issuer rating to BBB+, senior secured debt to A, subordinated debt to BBB+, and preferred stock to BBB+. The rating outlook was changed to stable. Fitch stated that these downgrades were because of deteriorating financial measures over the past several years and the expectation that they will not improve materially without further rate support. They noted the financial deterioration is primarily due to increasing fuel and operating costs and a large capital expenditure program.
Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power and gas supply, among other things, resulting in a negative impact on earnings. Collateral postings and prepayments made with external parties at March 31, 2009, were $193 million, $23 million, $40 million, $43 million, $43 million, and $76 million at Ameren, UE, CIPS, CILCORP, CILCO and IP, respectively. The amount of collateral external counterparties posted with Ameren was $38 million at March 31, 2009. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3” from S&P or Moody’s, respectively) at March 31, 2009, could have resulted in Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP being required to post additional collateral or other assurances for certain trade obligations amounting to $324 million, $119 million, $17 million, $44 million, $34 million, $34 million, and $43 million, respectively.
In addition, changes in commodity prices could trigger additional collateral postings and prepayments. If market prices were 15% higher than March 31, 2009 levels in the next twelve months and 20% higher thereafter through the end of the term of the commodity contracts, then Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP could be required to post additional collateral or other assurances for certain trade obligations up to approximately $106 million, $44 million, $3 million, $- million, $10 million, $10 million, and $- million, respectively. If market prices were 15% lower than March 31, 2009 levels in the next twelve months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP could be required to post additional collateral or other assurances for certain trade obligations up to approximately $434 million, $186 million, $33 million, $- million, $94 million, $94 million, and $89 million, respectively.
The cost of borrowing under our credit facilities can increase or decrease depending upon the credit ratings of the borrower. A credit rating is not a recommendation to buy, sell or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.
OUTLOOK
Below are some key trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2009 and beyond.
Economy and Capital and Credit Markets
The global capital and credit markets experienced extreme volatility and disruption in 2008 and early 2009, and we expect those conditions to continue throughout the rest of 2009 and potentially longer. Several factors have driven this situation, including deteriorating global economic conditions and the weakened condition of major financial institutions. These conditions have led governments around the world to establish policies and programs that are designed to strengthen the global financial system, to
84
enhance liquidity, and to restore investor confidence. We believe that these events have several implications for the capital and credit markets, the economy and our industry as a whole, including Ameren. They include the following:
Access to Capital Markets and Cost of Capital - The extreme disruption in the capital markets has limited the ability of many companies, including the Ameren Companies, to freely access the capital and credit markets to support their operations and to refinance debt. Ameren’s regulated utilities have continued to have access to the capital markets at commercially acceptable, but higher, rates as evidenced by CILCO’s, IP’s, and UE’s sale of senior secured notes in late 2008 and early 2009. Ameren expects access to the capital markets for its non-rate-regulated subsidiaries to be more difficult and costly. CILCORP and IP have long-term debt maturities of $124 million and $250 million, respectively, in 2009. In addition, Ameren’s $300 million term loan agreement matures in 2009. We currently plan to issue approximately $250 million of debt at our rate-regulated utilities, $425 million at Ameren, and approximately $500 million at our non-rate-regulated generation subsidiaries during the remainder of 2009.
Credit Facilities - At March 31, 2009, the Ameren Companies had in place revolving bank credit facilities aggregating $2.15 billion. In total, 18 financial institutions participated in these credit facilities. In January 2010, $1 billion of these facilities expire, and the other $1.15 billion facility expires in July 2010. Due to the Lehman bankruptcy filing, the size of these facilities was effectively reduced by up to $121 million. We cannot predict whether other lenders that are currently participating in our credit facilities will declare bankruptcy or otherwise fail to honor their commitments thereunder, and thus reduce the level of access to credit facilities. We are actively developing plans and strategies to renew these facilities prior to their expiration dates. We are unable to predict the degree of success we will have in renewing or replacing any of these facilities and whether the size and terms of any new credit facilities will be comparable to the existing facilities. In addition, we expect the costs of new credit facilities to be significantly higher.
Economic Conditions - Limited access to capital and credit and higher cost of capital for businesses and consumers are expected to reduce spending and investment, result in job losses, and pressure economic growth. The current weak economic conditions will likely result in weaker power and commodity markets, greater risk of defaults by our counterparties, weaker customer sales growth, particularly with respect to industrial sales, higher bad debt expense, higher financing costs, and possible impairment of goodwill and long-lived assets, among other things. Due to a significant decline in Ameren’s market capitalization, the continuing decline in market prices for electricity, and a decrease in observable industry market multiples, CILCORP’s Illinois Regulated and CILCORP’s Non-rate-regulated Generation reporting units recorded an impairment charge of $462 million as of March 31, 2009. Ameren’s reporting units and IP’s reporting unit did not require an impairment of goodwill in the first quarter of 2009. However, the estimated fair values of Ameren’s Illinois Regulated reporting unit, Ameren’s Non-rate-regulated Generation reporting unit, and IP’s Illinois Regulated reporting unit exceeded their carrying value by a nominal amount as of March 31, 2009. As a result, the failure in the future of any reporting unit to achieve forecasted operating results and cash flows or a further decline of observable industry market multiples may reduce its estimated fair value below its carrying value and would likely result in the recognition of a goodwill impairment charge. Ameren, CILCORP and IP will continue to monitor the actual and forecasted operating results, cash flows, market capitalization, market prices for electricity and observable industry market multiples of their reporting units for signs of possible declines in estimated fair value and potential goodwill impairment. We are unable to predict the ultimate impact of these weak economic conditions on our results of operations, financial position, or liquidity.
Investment Returns - The disruption in the capital markets, coupled with weak global economic conditions, has adversely affected financial markets. As a result, we experienced lower than assumed investment returns in 2008 in our pension and postretirement benefit plans. These lower returns will increase our future pension and postretirement expenses and pension funding levels. Our future expenses and funding levels will also be affected by future discount rate levels. Based on Ameren's assumptions at December 31, 2008, and investment performance in 2008, and reflecting Ameren’s pension funding policy, Ameren expects to make annual contributions of $90 million to $200 million in each of the next five years. In the first quarter of 2009, we experienced lower than assumed investment returns in our pension and postretirement benefit plans, which could impact future expenses and funding levels.
Operating and Capital Expenditures - The Ameren Companies will continue to make significant levels of investments and incur expenditures for their electric and natural gas utility infrastructure in order to improve overall system reliability, comply with environmental regulations, and improve plant performance. However, due to the significant level of disruption and uncertainties in the capital and credit markets, we are actively evaluating opportunities to defer or reduce planned capital spending and operating expenses to mitigate the risks associated with accessing these uncertain markets. We took action in this regard by reducing 2009 operating and capital expenditures from levels previously expected.
85
Separately, within a pending rulemaking, Genco, AERG and EEI received approval from the Illinois Pollution Control Board, subject to Illinois Joint Committee on Administrative Rules review and approval, to a variance from an environmental requirement in Illinois that, while "environmentally neutral," would defer an estimated $375 million of Genco’s environmental capital expenditures scheduled for 2009 through 2012 to subsequent years. Any expenditure control initiatives will be balanced against a continued long-term commitment to invest in our electric and natural gas infrastructure to provide safe, reliable electric and natural gas delivery services to our customers; to meet federal and state environmental, reliability, and other regulations; and the need to maintain a solid overall liquidity and credit ratings profile to meet our operating, capital and financing needs under challenging capital and credit market conditions.
Liquidity - At March 31, 2009, Ameren, on a consolidated basis, had available liquidity, in the form of cash on hand and amounts available under its existing credit facilities, of approximately $1.7 billion, excluding unfunded Lehman bank facility participation commitments, which was $1.1 billion higher than the same time last year. We expect our available liquidity to remain at acceptable levels through the end of 2009 as we strategically access the capital markets and execute expenditure control initiatives. However, we are unable to predict whether significant changes in economic conditions, further disruption in the capital and credit markets, or other unforeseen events could materially impact our expectation.
Although we believe that the uncertainty in the capital and credit markets will persist throughout 2009 and potentially longer, we do believe that actions taken by the U.S. government and governments around the world will ultimately help ease the extreme volatility and disruption of these markets. In addition, we believe we will continue to have access to the capital markets on terms commercially acceptable to us. As discussed above, additional financings are expected through 2009, subject to market conditions. Also, in February 2009, Ameren’s board of directors made the decision to reduce the common stock dividend. Specifically, this dividend reduction would be consistent with an annual dividend level that would allow Ameren to retain approximately $215 million of cash annually, which would provide incremental funds to enhance reliability to meet our customers’ expectations; satisfy federal and state environmental requirements; reduce our reliance on dilutive equity and high cost debt financings; and enhance our access to the capital and credit markets. We believe that our expected operating cash flows, capital expenditures, and related financing plans (including accessing our existing credit facilities) will provide the necessary liquidity to meet our operating, investing, and financing needs through the end of 2009, at a minimum. However, there can be no assurance that significant changes in economic conditions, further disruptions in the capital and credit markets, or other unforeseen events will not materially impact our ability to execute our expected operating, capital or financing plans, including our plans to renew or replace our existing credit facilities.
Current Capital Expenditure Plans
Between 2009 and 2018, Ameren expects that certain Ameren Companies will be required to invest between $4.5 billion and $5.5 billion to retrofit their coal-fired power plants with pollution control equipment in compliance with emissions-related environmental laws and regulations. Any pollution control investments will result in decreased plant availability during construction and significantly higher ongoing operating expenses. Approximately 50% of this investment is expected to be in our Missouri Regulated operations, and it is therefore expected to be recoverable from ratepayers. The recoverability of amounts expended in Non-rate-regulated Generation operations will depend on whether market prices for power adjust as a result of market conditions reflecting increased environmental costs for generators.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs. Excessive costs to comply with future legislation or regulations might force Ameren and other similarly situated electric power generators to close some coal-fired facilities. Investments to control carbon emissions at Ameren’s coal-fired power plants would significantly increase future capital expenditures and operation and maintenance expenses.
UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. UE’s integrated resource plan filed with the MoPSC in February 2008 included the expectation that new baseload generation capacity would be required in the 2018 to 2020 timeframe. However, due to the significant time required to plan, acquire permits for, and build a baseload power plant, UE continues to study future plant alternatives.
In July 2008, UE filed an application with the NRC for a combined construction and operating license for a potential new 1,600-megawatt nuclear unit at UE’s existing Callaway County, Missouri nuclear plant site. Pursuant to the DOE’s procedures, in 2008 UE filed with the DOE Part I and Part II of its application for a loan guarantee to support the potential construction of a new nuclear unit. UE has also signed contracts for COLA services and certain long lead-time nuclear-unit related equipment (heavy forgings). The filing of the COLA and the DOE loan guarantee application and entering into
86
these contracts did not mean a decision had been made to build a new nuclear unit. These were only the first steps in the regulatory licensing and procurement process. They were necessary actions to preserve the option to develop a new nuclear unit to supply power to UE’s customers.
UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license by 20 years so that the operating license will expire in 2044. UE cannot predict whether or when the NRC will approve the license extension.
Over the next few years, we expect to make significant investments in our electric and natural gas infrastructure and to incur increased operations and maintenance expenses to improve overall system reliability. We are projecting higher labor and material costs for these capital expenditures. We expect these costs or investments at our rate-regulated businesses to be ultimately recovered in rates, although regulatory lag could materially impact our cash flows and related financing needs.
Increased investments for environmental compliance, reliability improvement, and new baseload capacity will result in higher depreciation and financing costs.
The earnings of UE, CIPS, CILCO and IP are largely determined by the regulation of their rates by state agencies. Rising costs, including labor, material, depreciation and financing costs, coupled with increased capital and operations and maintenance expenditures targeted at enhanced distribution system reliability and environmental compliance, are expected. Ameren, UE, CIPS, CILCO and IP anticipate regulatory lag until requests to increase rates to continue to recover such costs on a timely basis are granted by state regulators. Ameren, UE, CIPS, CILCO and IP expect more frequent rate cases will be necessary in the future. UE has agreed not to file a natural gas delivery rate case before March 15, 2010.
The ICC issued a consolidated order in September 2008 approving a net increase in annual revenues for electric delivery service of $123 million in the aggregate (CIPS - $22 million increase, CILCO - $3 million decrease and IP - $104 million increase) and a net increase in annual revenues for natural gas delivery service of $38 million in the aggregate (CIPS - $7 million increase, CILCO - $9 million decrease, and IP - $40 million increase), based on a 10.65% return on equity with respect to electric delivery service and a 10.68% return on equity with respect to natural gas delivery service. These rate changes were effective on October 1, 2008. Because of the Ameren Illinois Utilities’ pledge to keep the overall residential electric bill increase resulting from these rate changes during the first year to less than 10% for each utility, IP will not recover approximately $10 million in revenue in the first year the electric delivery service rates are in effect. Thereafter, residential electric delivery service rates will be adjusted to recover the full increase. In addition, the ICC changed the depreciable lives used in calculating depreciation expense for the Ameren Illinois Utilities’ electric and natural gas rates. As a result, annual depreciation expense for the Ameren Illinois Utilities will be reduced for financial reporting purposes
87
by a net $13 million in the aggregate (CIPS - $4 million reduction, CILCO - $26 million reduction, and IP - $17 million increase).
Because of continuing investments in the Ameren Illinois Utilities’ infrastructure, rising operating costs and costs of capital, the Ameren Illinois Utilities are not expected to earn the return on equity allowed in the ICC September 2008 consolidated order. As a result, rate case filings with the ICC are being targeted for late in the second quarter or early in the third quarter of 2009.
The MoPSC issued an electric rate order in January 2009 approving an increase in annual electric revenues of approximately $162 million based on a 10.76% return on equity, a capital structure composed of 52% common equity, and a rate base of $5.8 billion. New rates were effective March 1, 2009. In addition, pursuant to the accounting order issued by the MoPSC in April 2008, the rate order concluded that the $25 million of operations and maintenance expenses incurred as a result of a severe ice storm in January 2007 should be amortized and recovered over a five-year period starting March 1, 2009. The MoPSC also allowed recovery of $12 million of costs associated with a March 2007 FERC order that resettled costs among MISO market participants. UE recorded a regulatory asset for these costs at December 31, 2008, which will be amortized and recovered over a two-year period beginning March 1, 2009.
Because of continuing investments in UE’s utility infrastructure, rising operating costs and costs of capital, UE is not expected to earn the return on equity allowed in the MoPSC’s January 2009 electric rate order during 2009. As a result, UE expects to file another electric rate case in Missouri later this year. The exact timing will depend on the timing and magnitude of cost increases and rate base additions, among other things.
In current and future rate cases, UE, CIPS, CILCO and IP will continue to seek cost recovery and tracking mechanisms from their state regulators to reduce regulatory lag. In the ICC consolidated electric and natural gas rate order issued in September 2008, the ICC order approved an increase in the percentage of costs to be recovered through fixed non-volumetric residential and commercial natural gas customer charges to 80% from 53%. This increase will impact 2009 quarterly results of operations and cash flows but is not expected to have any impact on annual margins. The ICC also approved an increase in the Supply Cost Adjustment (SCA) factors for the Ameren Illinois Utilities. The SCA is a charge applied only to the bills of customers who take their power supply from the Ameren Illinois Utilities. The change in the SCA factors is expected to result in increased electric revenues of $9.5 million per year in the aggregate (CIPS - $2.6 million, CILCO - $1.6 million, and IP - $5.3 million) covering the increased cost of administering the Ameren Illinois Utilities’ power supply responsibilities. In the MoPSC electric rate order issued in January 2009, the MoPSC approved UE’s implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism. The FAC allows an adjustment of electric rates three times per year for a pass-through to customers of 95% of changes in fuel and purchased power costs, net of off-system revenues, including MISO costs and revenues, above or below the amount set in base rates, subject to MoPSC prudency review. The vegetation management and infrastructure inspection cost tracking mechanism provides for the tracking of expenditures that are greater or less than amounts provided for in UE’s annual revenues for electric service in a particular year, subject to a 10% limitation on increases in any one year. The tracked amounts may be reflected in rates set in future rate cases.
UE provides power to Noranda’s smelter plant in New Madrid, Missouri, which has historically used approximately four million megawatthours of power annually, making Noranda UE’s single largest customer. As a result of a major winter ice storm in January 2009, Noranda’s smelter plant experienced a power outage related to non-UE lines delivering power to the substation serving the plant. Noranda stated in its Annual Report on Form 10-K for the year ended December 31, 2008, that the outage affected approximately 75% of the smelter plant’s capacity. In a May 6, 2009 press release, Noranda stated that its smelter plant was operating above 50% of capacity. In addition, Noranda stated that although it has the capability to restart all lines by year-end, management continues to assess the damage to its lines and is managing the restart timeline to optimize the effective return to capacity. To the extent UE’s sales to Noranda are reduced, UE’s margins may be reduced. UE estimates its electric margin from sales to Noranda was $10 million lower during the first quarter of 2009, compared with the same period in 2008, as a result of the outage. UE continues to consider alternatives to recover any lost revenues resulting from the Noranda power outage.
The Illinois electric settlement agreement reached in 2007 provides approximately $1 billion over a four-year period that began in 2007 to fund rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. Funding for the settlement is coming from electric generators in Illinois and certain Illinois electric utilities. The Ameren Illinois Utilities, Genco, and AERG agreed to fund an aggregate of $150 million, of which the following contributions remained to be made at March 31, 2009:
88
In January 2009, the ICC approved the electric power procurement plan filed by the IPA for both the Ameren Illinois Utilities and Commonwealth Edison Company. The plan outlined the wholesale products (capacity, energy swaps, and renewable energy credits) that the IPA will procure on behalf of the Ameren Illinois Utilities for the period of June 1, 2009, through May 30, 2014. The products are being procured through a RFP process, during the first half of 2009. The capacity RFP was completed in April 2009. Marketing Company and UE were among the winning bidders. The Ameren Illinois Utilities will be allowed to pass through to customers the costs of procuring electric power supply with no markup by the utility, plus any reasonable costs that the utility incurs in arranging and providing for the supply of electric power.
As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock in energy prices for 400 to 1,000 megawatts annually of their round-the-clock power requirements during the period June 1, 2008 to December 31, 2012, at then-relevant market prices. These financial contracts do not include capacity, are not load-following products and do not involve the physical delivery of energy. Under the terms of the Illinois electric settlement agreement, these financial contracts are deemed prudent, and the Ameren Illinois Utilities are permitted full recovery of their costs in rates.
In addition, the Illinois electric settlement agreement would allow the Ameren Illinois Utilities to lease or invest in generation facilities, subject to ICC approval.
Volatile power prices in the Midwest can affect the amount of revenues Ameren, Genco, CILCO (through AERG) and EEI generate by marketing power into the wholesale and spot markets and can influence the cost of power purchased in the spot markets. Spot power prices in the MISO were lower during the first quarter of 2009 compared with the same period in 2008, and are expected to remain lower compared to 2008 for the remainder of the year.
The availability and performance of Genco’s, AERG’s and EEI’s electric generation fleet can materially impact their revenues. Genco and AERG are seeking to raise the equivalent availability and capacity factors of their power plants over the long term through greater investments and a process improvement program. The Non-rate-regulated Generation segment expects to generate 30 million megawatthours of power in 2009 (Genco - 16 million, AERG - 7 million, EEI - 7 million) based on expected power prices in 2009. Should power prices rise more than expected in 2009, the Non-rate-regulated Generation segment has the capacity and availability to sell more generation.
In 2008, two million contracted megawatthours of Genco’s and AERG’s legacy power supply agreements, which had an average embedded selling price of $33 per megawatthour, expired. These agreements were replaced with market-based sales.
The marketing strategy for the Non-rate-regulated Generation segment is to optimize generation output in a low risk manner to minimize volatility of earnings and cash flow, while seeking to capitalize on its low-cost generation fleet to provide solid, sustainable returns. To accomplish this strategy, the Non-rate-regulated Generation segment has established hedge targets for near-term years. Through a mix of physical and financial sales contracts, Marketing Company targets to hedge Non-rate-regulated Generation’s expected output by 80% to 90% for the following year, 50% to 70% for two years out, and 30% to 50% for three years out. As of March 31, 2009, Marketing Company had sold 100% of Non-rate-regulated Generation’s expected 2009 generation, at an average price of $53 per megawatthour, and had sold approximately 60% of Non-rate-regulated Generation’s 2010 generation at an average price of $51 per megawatthour.
The development of ancillary services and capacity markets in MISO could increase the electric margins of Genco, AERG and EEI. Ancillary services are services necessary to support the transmission of energy from generation resources to loads while maintaining reliable operation of the transmission provider’s system. MISO’s regional wholesale ancillary services market began in January 2009. MISO continues to refine its treatment of capacity supply and obligations, but development of a true capacity market could still be several years away. A capacity requirement obligates a load serving entity to acquire capacity sufficient to meet its obligations.
Future energy efficiency programs developed by UE, CIPS, CILCO and IP and others could result in reduced demand for our electric generation and our electric and gas transmission and distribution services.
Fuel and Purchased Power
In 2008, 85% of Ameren’s electric generation (UE - 77%, Genco - 99%, AERG - 99%, EEI - 100%) was supplied by coal-fired power plants. About 96% of the coal used by these plants (UE - 97%, Genco - 98%, AERG - 77%, EEI - 100%) was delivered by rail from the Powder River Basin in Wyoming. In the past, deliveries from the Powder River Basin have been restricted because of rail maintenance, weather, and derailments. As of March 31, 2009, coal inventories for UE, Genco, AERG and EEI were at targeted levels. Disruptions in coal deliveries could cause UE, Genco, AERG and EEI to pursue a strategy that could include reducing sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources.
89
Genco is incurring incremental fuel costs in 2009 to replace coal from an Illinois mine that was prematurely closed by its owner at the end of 2007. A settlement agreement reached with the coal mine owner in June 2008 fully reimbursed Genco, in the form of a lump-sum payment of $60 million, for increased costs for coal and transportation that it incurred in 2008 ($33 million) and expects to incur in 2009 ($27 million). The entire settlement was recorded in 2008 earnings, so Ameren’s and Genco’s earnings in 2009 will be lower than they otherwise would have been.
•
The annual NOxtrading program under the federal Clean Air Interstate Rule was reinstated by the U.S. Court of Appeals for the District of Columbia in December 2008. At this time, Genco and AERG may not have sufficient NOx allowances to meet forecasted 2009 obligations under the annual NOx trading program. The costs of these allowances would depend on market prices at the time these allowances are purchased. Genco and AERG currently estimate that they could incur additional fuel expense in 2009 of $1 million and $4 million, respectively, to purchase additional NOx allowances to comply with the program.
Ameren’s fuel costs (including transportation) are expected to increase in 2009 and beyond. See Item 3 - Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about the percentage of fuel and transportation requirements that are price-hedged for 2009 through 2013.
Other Costs
In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. UE has settled with the FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident. In addition, UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant and is in the process of rebuilding the facility. The estimated cost to rebuild the upper reservoir is in the range of $480 million. UE expects the Taum Sauk plant to be out of service through early 2010. UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the plant, and the cost of replacement power, up to $8 million annually, will be covered by insurance. Insurance will not cover lost electric margins and penalties paid to FERC. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. See Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for further discussion of Taum Sauk matters.
UE’s Callaway nuclear plant had a 28-day scheduled refueling and maintenance outage during the fourth quarter of 2008. UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage is in the spring of 2010. During a scheduled outage, which occurs every 18 months, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases, versus non-outage years.
On February 20, 2009, the Illinois Supreme Court handed down its decision in Exelon Corporation v. The Department of Revenue, which concluded that an electric utility in Illinois qualifies for the Illinois investment tax credit. The decision in the case may have implications for the Ameren Companies’ income, sales and use taxes. On March 13, 2009, the Illinois Department of Revenue (IDOR) filed a Petition for Rehearing with the Illinois Supreme Court with respect to that court’s decision. As of March 31, 2009, IDOR’s Petition for Rehearing was still pending. The Ameren Companies continue to assess the impact the decision may have on their results of operations, financial position or liquidity.
Over the next few years, we expect rising employee benefit costs, as well as higher insurance premiums as a result of insurance market conditions and loss experience, among other things.
Under an executory tolling agreement, CILCO purchased steam, chilled water, and electricity from Medina Valley, which CILCO in turn sold to an industrial customer. In January 2009, CILCO transferred both the tolling agreement and the related power supply agreement with the industrial customer to Marketing Company. The transfer of these agreements is expected to benefit CILCO’s non-rate-regulated 2009 pretax operating generation income by $6 million compared with its 2008 operating income.
A ballot initiative passed by Missouri voters in November 2008 created a renewable energy portfolio standard. UE and other Missouri investor-owned utilities will be required to purchase or generate electricity from renewable energy sources equaling at least 2% of native load sales by 2011, with that percentage increasing in subsequent years to at least 15% by 2021, subject to a 1% limit on customer rate impacts. At least 2% of each portfolio standard must be derived from solar energy. Compliance with the renewable energy portfolio standard can be achieved through the procurement of renewable energy or renewable energy credits. Rules implementing the renewable energy portfolio standard are expected to be issued by the MoPSC in 2009. UE expects that any related costs or investments would ultimately be recovered in rates.
90
Ameren and Genco are currently considering divestiture of some of Genco’s smaller non-rate-regulated generating units.
The above items could have a material impact on our results of operations, financial position, or liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, or liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s stockholder value. We are unable to predict which, if any, of these initiatives will be executed. The execution of these initiatives may have a material impact on our future results of operations, financial position, or liquidity.
REGULATORY MATTERS
See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.
Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset. 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 nonfinancial or nonquantifiable. Such risks, principally business, legal and operational risks, are not part of the following discussion.
Our risk management objective is to optimize our physical generating assets and pursue market opportunities within prudent risk parameters. Our risk management policies are set by a risk management steering committee, which is composed of senior-level Ameren officers.
Except as discussed below, there have been no material changes to the quantitative and qualitative disclosures about market risk in the Form 10-K. See Item 7A under Part II of the Form 10-K for a more detailed discussion of our market risks.
Interest Rate Risk
We are exposed to market risk through changes in interest rates. The following table presents the estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 1% on variable-rate debt outstanding at March 31, 2009:
Ameren(b)
The estimated changes above do not consider potential reduced overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would probably act 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, this 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. NYMEX-traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction. See Note 6 - Derivative Financial Instruments to our financial statements under Part I, Item 1, of this report for information on the potential loss on counterparty exposure as of March 31, 2009.
Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. Our physical and financial instruments are subject to credit risk consisting of trade accounts receivable 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 who make up our customer base. At March 31, 2009, no nonaffiliated customer represented more than
91
10%, in the aggregate, of our accounts receivable. UE and the Ameren Illinois Utilities continue to monitor the impact of increasing rates and a weakening economic environment on customer collections. These companies make adjustments to their allowance for doubtful accounts as deemed necessary, to ensure that such allowances are adequate to cover estimated uncollectible customer account balances.
UE, CIPS, Genco, CILCO, AERG, IP, AFS and Marketing Company may have credit exposure associated with interchange or wholesale purchase and sale activity with nonaffiliated companies. At March 31, 2009, UE’s, CIPS’, Genco’s, CILCO’s, AERG’s, IP’s, AFS’ and Marketing Company’s combined credit exposure to nonaffiliated non-investment-grade trading counterparties was $1 million, net of collateral (2008 - $3 million). We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program that involves daily exposure reporting to senior management, master trading and netting agreements, and credit support, such as letters of credit and parental guarantees. We also analyze each counterparty’s financial condition before we enter into sales, forwards, swaps, futures or option contracts, and we monitor counterparty exposure associated with our leveraged lease. We estimate our credit exposure to MISO associated with the MISO Day Two Energy Market to be $33 million at March 31, 2009 (2008 - $78 million).
The Ameren Illinois Utilities will be exposed to credit risk in the event of nonperformance by the parties contributing to the Illinois comprehensive rate relief and assistance programs under the Illinois electric settlement agreement. The agreement provides $488 million in rate relief over a four-year period that commenced in 2007. Under funding agreements among the parties contributing to the rate relief and assistance programs, at the end of each month, the Ameren Illinois Utilities will bill the participating generators for their proportionate share of that month’s rate relief and assistance, which is due in 30 days, or drawn from the funds provided by the generators’ escrow. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for additional information.
Equity Price Risk
Our costs of providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. To the extent the value of plan assets declines, the effect would be reflected in net income and OCI or regulatory assets, and in the amount of cash required to be contributed to the plans.
Foreign Currency Risk
Ameren and UE are exposed to foreign currency exchange risk from UE’s procurement agreement for heavy forgings. The agreement requires UE to pay for goods and services rendered in euros. UE uses foreign currency forward contracts for the purchase of euros to mitigate the impact of changes in foreign currency exchange rates, which could affect the amount of U.S. dollars required to satisfy the obligation denominated in euros. To the extent the value of the U.S. dollar versus the euro declines, the effect would be reflected in construction work in process within property and plant, net, and subject to routine depreciation and impairment considerations.
Commodity Price Risk
We are exposed to changes in market prices for electricity, fuel, and natural gas. UE’s, Genco’s, AERG’s and EEI’s risks of changes in prices for power sales are partially hedged through sales agreements. Genco, AERG and EEI also seek to sell power forward to wholesale, municipal and industrial customers to limit exposure to changing prices. We also attempt to mitigate financial risks through structured risk management programs and policies, which include forward-hedging programs, and the use of derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts). However, a portion of the generation capacity of UE, Genco, AERG and EEI is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices.
The following table shows how Ameren’s cumulative earnings might decrease if power prices were to decrease by 1% on unhedged economic generation for the remainder of 2009 through 2012:
Ameren also uses its portfolio management and trading capabilities both to manage risk and to deploy risk capital to generate additional returns. Due to our physical presence in the market, we are able to identify and pursue opportunities, which can generate additional returns through portfolio management and trading activities. All of this activity is performed within a controlled risk management process. We establish value at risk (VaR) and stop-loss limits that are intended to prevent any material negative financial impact.
92
We manage risks associated with changing prices of fuel for generation using similar techniques as those used to manage risks associated with changing market prices for electricity. Most UE, Genco, AERG and EEI fuel supply contracts are physical forward contracts. Genco, AERG and EEI do not have the ability to pass through higher fuel costs to their customers for electric operations. Prior to March 2009, UE did not have this ability either except through a general rate proceeding. As a part of the January 2009 MoPSC electric rate order, UE was granted permission to put a FAC in place, which was effective March 1, 2009. The FAC allows UE to recover directly from its electric customers 95% of changes in fuel and purchased power costs, net of off-system revenues, including MISO costs and revenues, above or below the amount set in base rates, subject to MoPSC prudency review. Thus, UE remains exposed to 5% of changes in its fuel and purchased power costs, net of off-system revenues. UE, Genco, AERG and EEI have entered into long-term contracts with various suppliers to purchase coal to manage their exposure to fuel prices. The coal hedging strategy is intended to secure a reliable coal supply while reducing exposure to commodity price volatility. Price and volumetric risk mitigation is accomplished primarily through periodic bid procedures, whereby the amount of coal purchased is determined by the current market prices and the minimum and maximum coal purchase guidelines for the given year. UE, Genco, AERG and EEI generally purchase coal up to five years in advance, but we may purchase coal beyond five years to take advantage of favorable deals or market conditions. The strategy also allows for the decision not to purchase coal to avoid unfavorable market conditions.
Transportation costs for coal and natural gas can be a significant portion of fuel costs. UE, Genco, AERG and EEI typically hedge coal transportation forward to provide supply certainty and to mitigate transportation price volatility. Natural gas transportation expenses for Ameren’s gas distribution utility companies and the gas-fired generation units of UE, Genco, AERG and EEI are regulated by FERC through approved tariffs governing the rates, terms and conditions of transportation and storage services. Certain firm transportation and storage capacity agreements held by the Ameren Companies include rights to extend the contracts prior to the termination of the primary term. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariff rates for our requirements.
The following table presents the percentages of the projected required supply of coal and coal transportation for our coal-fired power plants, nuclear fuel for UE’s Callaway nuclear plant, natural gas for our CTs and retail distribution, as appropriate, and purchased power needs of CIPS, CILCO and IP, which own no generation, that are price-hedged over the remainder of 2009 through 2013, as of March 31, 2009. The projected required supply of these commodities could be significantly impacted by changes in our assumptions for such matters as customer demand of our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.
Coal transportation
Nuclear fuel
Natural gas for generation
Natural gas for distribution(a)
Purchased power for Illinois Regulated(b)
Purchased power(b)
CILCORP/CILCO:
Coal (AERG)
Coal transportation (AERG)
93
EEI:
The following table shows how our cumulative fuel expense might increase and how our cumulative net income might decrease if coal and coal transportation costs were to increase by 1% on any requirements not currently covered by fixed-price contracts for the period 2009 through 2013.
Expense
Net
Income(a)
In addition, coal and coal transportation costs are sensitive to the price of diesel fuel as a result of rail freight fuel surcharges. Ameren utilizes a combination of swaps and purchased call options to price cap and price hedge this exposure. If diesel fuel costs were to increase or decrease by $0.25/gallon, Ameren’s fuel expense could increase or decrease by $10 million annually for 2009 (UE - $5 million, Genco - $2 million, AERG - $1 million and EEI - $2 million). As of March 31, 2009, Ameren had a price cap for 100% of expected fuel surcharges in 2009.
In the event of a significant change in coal prices, UE, Genco, AERG and EEI would probably take actions to further mitigate their exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure or fuel sources.
With regard to exposure for commodity price risk for nuclear fuel, UE has fixed-priced and base-price-with- escalation agreements, or it uses inventories that provide some price hedge to fulfill its Callaway nuclear plant needs for uranium, conversion, enrichment, and fabrication services. There is no fuel reloading scheduled for 2009 or 2012. UE has price hedges for 87% of the 2010 to 2013 nuclear fuel requirements.
Nuclear fuel market prices remain subject to an unpredictable supply and demand environment. UE has continued to follow a strategy of managing inventory of nuclear fuel as an inherent price hedge. New long-term uranium contracts are almost exclusively market-price-related with an escalating price floor. New long-term enrichment contracts usually have some market-price-related component. UE expects to enter into additional contracts from time to time in order to supply nuclear fuel during the expected life of the Callaway nuclear plant, at prices which cannot now be accurately predicted. Unlike the electricity and natural gas markets, nuclear fuel markets have limited financial instruments available for price hedging, so most hedging is done through inventories and forward contracts, if they are available.
See Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for further information regarding the long-term commitments for the procurement of coal, natural gas and nuclear fuel.
Fair Value of Contracts
Most of our commodity contracts qualify for treatment as NPNS. We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity, FTRs and emission allowances. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the three months ended March 31, 2009. We use various methods to determine the fair value of our contracts. In accordance with SFAS No. 157 hierarchy levels, our sources used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). All of these contracts have maturities of less than five years. See Note 7 - Fair Value Measurements to our financial statements under Part I, Item 1, of this report for further information regarding the methods used to determine the fair value of these contracts.
94
Three Months Ended March 31, 2009
Fair value of contracts at beginning of period, net
Contracts realized or otherwise settled during the period
Changes in fair values attributable to changes in valuation technique and assumptions
Fair value of new contracts entered into during the period
Other changes in fair value
Fair value of contracts outstanding at the end of period, net
The following table presents maturities of derivative contracts as of March 31, 2009, based on the hierarchy levels used to determine the fair value of the contracts:
Maturity
Less than
1 Year
1-3 Years
4-5 Years
Maturity in
Excess of
5 Years
Fair Value
Level 1
Level 2(a)
Level 3(b)
(b)
Principally coal and SO2 option values based on a Black-Scholes model that includes information from external sources and our estimates. Also includes interruptible power forward and option contract values based on our estimates.
ITEM 4 and ITEM 4T. CONTROLS AND PROCEDURES.
As of March 31, 2009, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon those evaluations, the principal executive officer and principal financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.
95
There has been no change in any of the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, each of their internal control over financial reporting.
PART II. OTHER INFORMATION
We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses.
For additional information on legal and administrative proceedings, see Note 2 - Rate and Regulatory Matters, Note 8 - Related Party Transactions and Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1 of this report.
There have been no material changes to the risk factors disclosed in Item 1A. Risk Factors in the Form 10-K.
The following table presents Ameren Corporation’s purchases of equity securities reportable under Item 703 of Regulation S-K:
(a) Total Number
of Shares
(or Units)Purchased(a)
(b) Average Price
Paid per Share
(or Unit)
January 1 - January 31, 2009
February 1 - February 28, 2009
March 1 - March 31, 2009
None of the other registrants purchased equity securities reportable under Item 703 of Regulation S-K during the January 1 to March 31, 2009 period.
96
The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.
97
98
SIGNATURES
Pursuant to the requirements of the Exchange Act, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
(Registrant)
99
Date: May 8, 2009
100