-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, QUMn+5J8O8aPScQM+bsCfXXLHwdy1iI2TKVNmRwnamzkQvTtuY7OSbCKV5y4S5TA 3Ub+s2ADel4dPJbbO7ce0g== 0001002910-01-500055.txt : 20010815 0001002910-01-500055.hdr.sgml : 20010815 ACCESSION NUMBER: 0001002910-01-500055 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20010630 FILED AS OF DATE: 20010814 FILER: COMPANY DATA: COMPANY CONFORMED NAME: UNION ELECTRIC CO CENTRAL INDEX KEY: 0000100826 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 430559760 STATE OF INCORPORATION: MO FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-02967 FILM NUMBER: 1709955 BUSINESS ADDRESS: STREET 1: 1901 CHOUTEAU AVENUE STREET 2: MC 1370 CITY: ST LOUIS STATE: MO ZIP: 63166 BUSINESS PHONE: 3146213222 MAIL ADDRESS: STREET 1: 1901 CHOUTEAU AVENUE STREET 2: MC 1370 CITY: ST LOUIS STATE: MO ZIP: 63166 10-Q 1 ue012q.txt UEC 2ND QTR. 10 Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For Quarterly Period Ended June 30, 2001 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Transition Period From to Commission file number 1-2967. UNION ELECTRIC COMPANY (Exact name of registrant as specified in its charter) Missouri 43-0559760 (State or other jurisdiction (I.R.S. Employer incorporation or organization Identification No.) 1901 Chouteau Avenue, St. Louis, Missouri 63103 (Address of principal executive offices and Zip Code) Registrant's telephone number, including area code: (314) 621-3222 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X . No . ------------ -------------- Shares outstanding of each of registrant's classes of common stock as of August 14, 2001: Common Stock, $5 par value, held by Ameren Corporation (parent company of Registrant) - 102,123,834 Union Electric Company Index Page No. Part I Financial Information Item 1. Financial Statements (Unaudited) Balance Sheet - June 30, 2001 and December 31, 2000 10 Statement of Income - Three months, six months and 12 months ended June 30, 2001 and 2000 11 Statement of Cash Flows - Six months ended June 30, 2001 and 2000 12 Statement of Common Stockholder's Equity - Six months ended June 30, 2001 and 12 months ended December 31, 2000 13 Notes to Financial Statements 14 Item 2. Management's Discussion and Analysis of 2 Financial Condition and Results of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk 8 Part II Other Information Item 4. Submission of Matters to a Vote of Security Holders 19 Item 5. Other Information 19 Item 6. Exhibits and Reports on Form 8-K 19 PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS (UNAUDITED). The unaudited financial statements of Union Electric Company (AmerenUE or the Registrant) appear on pages 10 through 18 of this report. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. OVERVIEW The Registrant is a subsidiary of Ameren Corporation (Ameren), a holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA). Both Ameren and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Registrant is a public utility operating company engaged principally in the generation, transmission, distribution and sale of electric energy and the purchase, distribution, transportation and sale of natural gas in the states of Missouri and Illinois. The Registrant serves 1.2 million electric and 125,000 gas customers in a 24,500 square-mile area of Missouri and Illinois, including Metropolitan St. Louis. The Registrant's financial statements include charges for services that Ameren Services Company (Ameren Services), a wholly owned subsidiary of Ameren, provides to the Registrant. Ameren Services provides shared support services for all Ameren companies. Charges are based upon the actual costs incurred by Ameren Services, as required by PUHCA. The following discussion and analysis should be read in conjunction with the Notes to the Financial Statements beginning on page 14, and the Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the Audited Financial Statements, and the Notes to the Financial Statements appearing in the Registrant's 2000 Form 10-K. RESULTS OF OPERATIONS Earnings Second quarter 2001 earnings of $80 million decreased $4 million compared to 2000 second quarter earnings. Earnings for the six months ended June 30, 2001, decreased $5 million from the year ago period to $116 million. Earnings for the 12 months ended June 30, 2001 were $339 million, a $13 million decrease from the preceding 12-month period. Earnings fluctuated due to many conditions, primarily: sales growth, weather variations, credits to electric customers, electric rate reductions, gas rate increases, competitive market forces, fluctuating operating costs (including Callaway Nuclear Plant refueling outages), expenses relating to the withdrawal from the electric transmission related Midwest Independent System Operator (Midwest ISO), adoption of a new accounting standard, changes in interest expense, and changes in income and property taxes. The significant items affecting revenues, costs and earnings during the three-month, six-month and 12-month periods ended June 30, 2001 and 2000 are detailed on the following pages. Electric Operations
Electric Operating Revenues Variations for periods ended June 30, 2001 from comparable prior-year periods - ------------------------------------------------------------------------------------------------------------------------ (Millions of Dollars) Three Months Six Months Twelve Months ------------ ---------- ------------- - ------------------------------------------------------------------------------------------------------------------------ Credit to electric customers $ 30 $ 25 $ (7) Effect of abnormal weather 16 38 61 Growth and other 13 12 20 Interchange sales 42 103 140 - ------------------------------------------------------------------------------------------------------------------------ $ 101 $ 178 $ 214 - ------------------------------------------------------------------------------------------------------------------------
The $101 million increase in second quarter electric revenues compared to the year-ago quarter was primarily driven by an 8 percent increase in total kilowatthour sales. Residential, commercial and interchange sales increased 8 percent, 10 percent and 23 percent, respectively. These increases were partially offset by decreases in industrial and 2 wholesale sales. The increase in revenues was also attributed to a reduction in the estimated credits to Missouri electric customers (see Note 2 under Notes to Financial Statements for further information). Electric revenues for the first six months of 2001 increased $178 million compared to the same 2000 period primarily due to a 10 percent increase in total kilowatthour sales. Interchange sales increased 24 percent, while residential and commercial sales each increased 9 percent. These increases were partially offset by a decrease in wholesale sales. The increase in revenues was also attributed to a reduction in the estimated credits to Missouri electric customers (see Note 2 under Notes to Financial Statements for further information). Electric revenues for the 12 months ended June 30, 2001 increased $214 million compared to the prior 12-month period. The increase in revenues was primarily due to a 36 percent increase in interchange sales, coupled with increases of 10 percent and 6 percent in residential and commercial sales, respectively.
Fuel and Purchased Power Variations for periods ended June 30, 2001 from comparable prior-year periods - ---------------------------------------------------------------------------------------------------------------------- (Millions of Dollars) Three Months Six Months Twelve Months ------------ ---------- ------------- - ---------------------------------------------------------------------------------------------------------------------- Fuel: Generation $ (9) $ (4) $ 24 Price 7 11 (3) Generation efficiencies and other (1) (2) (3) Purchased power variation 85 124 121 - ---------------------------------------------------------------------------------------------------------------------- $ 82 $ 129 $ 139 - ----------------------------------------------------------------------------------------------------------------------
The increase in fuel and purchased power costs for the three-month, six-month and 12-month periods ended June 30, 2001 compared to the year ago comparable periods, was primarily due to increased purchased power resulting from higher sales volumes and the Callaway Nuclear Plant refueling, which occurred in the second quarter of 2001. Gas Operations Gas revenues for the six months and 12 months ended June 30, 2001 increased $27 million and $62 million, respectively, compared to the prior-year periods primarily due to increases in retail sales resulting from a return to more normal weather conditions, as compared to the same year ago periods, and higher gas costs recovered from customers through the Registrant's purchased gas adjustment clauses. Gas costs for the six months and 12 months ended June 30, 2001 increased $25 million and $50 million, respectively, compared to the year-ago periods, primarily due to higher sales and gas prices. Other Operating Expenses Other operating expense variations reflected recurring factors such as growth, inflation, labor and employee benefit cost increases and plant maintenance outages. Other operations expenses for the three, six and 12 months ended June 30, 2001 increased $12 million, $37 million and $91 million, respectively, compared to the same year-ago periods primarily due to higher employee benefit costs due to changes in actuarial assumptions and investment performance of employee benefit plans' assets, increases in professional services and automated meter reading services. Maintenance expenses for the three, six and 12 months ended June 30, 2001 increased $20 million, $26 million and $15 million, respectively, compared to the same year-ago periods primarily due to a refueling outage at the Registrant's Callaway Nuclear Plant during the second quarter of 2001. The spring 2001 refueling was completed in 45 days. There was no refueling in 2000. Depreciation and amortization expense for the six months and 12 months ended June 30, 2001 increased $4 million and $9 million, respectively, compared to the prior year periods due to an increase in depreciable property. Taxes Income taxes decreased $13 million, $10 million and $23 million, for the three, six and 12 months ended June 30, 2001, respectively, due to lower pretax income. 3 Other tax expense increased $5 million for the six months ended June 30, 2001 primarily due to increases in gross receipts tax resulting from increases in electric sales, compared to the year-ago period. Other tax expense increased $12 million for the 12 months ended June 30, 2001 due to increases in gross receipts tax and increased property tax assessments in the state of Missouri. Other Income and Deductions Miscellaneous, net increased $5 million for the 12 months ended June 30, 2001, compared to the year-ago period primarily due to prior period write-offs of certain nonregulated investments. Interest Expense Interest expense for the three months and six months ended June 30, 2001 decreased $4 million and $6 million, respectively, due to decreases in the nuclear fuel lease and commercial paper balances. Balance Sheet The $79 million decrease in intercompany notes receivable at June 30, 2001, compared to December 31, 2000, reflects changes in funds invested in a regulated money pool (see "Liquidity and Capital Resources" below and Note 3 under Notes to Financial Statements for further information). Changes in accounts and wages payable and taxes accrued resulted from the timing of various payments to taxing authorities and suppliers, including Ameren Services. The decrease in other current liabilities of $44 million is primarily due to the reduction in the estimated credit that the Registrant expects to pay its Missouri electric customers (see Note 2 under Notes to Financial Statements for further information). LIQUIDITY AND CAPITAL RESOURCES Cash provided by operating activities totaled $226 million for the six months ended June 30, 2001, compared to $161 million during the same 2000 period. Cash flows used in investing activities totaled $179 million and $171 million for the six months ended June 30, 2001 and 2000, respectively. Construction expenditures for the six months ended June 30, 2001, for constructing new or improving existing facilities were $252 million. In addition, the Registrant expended $13 million for the acquisition of nuclear fuel. The Registrant has made commitments to purchase four combustion turbine generating units totaling 192 megawatts to be located in Missouri and a 50 megawatt unit to be located at the Venice, Illinois plant that are expected to be operational by summer 2002. The cost of those units is approximately $125 million. Cash flows used in financing activities totaled $61 million for the six months ended June 30, 2001, compared to $106 million during the same 2000 period. The Registrant's principal financing activities for the period included the issuance and redemption of long-term debt and the payment of dividends. The Registrant plans to continue utilizing short-term debt to support normal operations and other temporary requirements. The Registrant is authorized by the Securities and Exchange Commission (SEC) under PUHCA to have up to $1 billion of short-term unsecured debt instruments outstanding at any one time. Short-term borrowings consist of bank loans (maturities generally on an overnight basis) and commercial paper (maturities generally within 1 to 45 days). At June 30, 2001, the Registrant had committed bank lines of credit aggregating $151 million (all of which was unused and available at such date) which make available interim financing at various rates of interest based on LIBOR, the bank certificate of deposit rate or other options. The lines of credit are renewable annually at various dates throughout the year. At June 30, 2001, the Registrant had no outstanding short-term borrowings. The Registrant also has a bank credit agreement due 2002 which permits the borrowing of up to $300 million on a long-term basis, all of which was unused, and $135 million was available at June 30, 2001. In addition, the Registrant has the ability to borrow up to approximately $488 million from Ameren or from two of Ameren's other subsidiaries, Central Illinois Public Service Company (AmerenCIPS) and Ameren Services, through a regulated money pool agreement. The total amount available to the Registrant at any given time from the regulated money pool is reduced by the amount of borrowings by AmerenCIPS or Ameren Services but increased to the extent AmerenCIPS or Ameren Services have surplus funds and the availability of other external borrowing sources. The 4 regulated money pool was established to coordinate and provide for certain short-term cash and working capital requirements of the Registrant, AmerenCIPS and Ameren Services and is administered by Ameren Services. Interest is calculated at varying rates of interest depending on the composition of internal and external funds in the regulated money pool. For the three months and six months ended June 30, 2001, the average interest rate for the regulated money pool was 4.38 percent and 4.94 percent, respectively. As of June 30, 2001, the Registrant had loaned $177 million to the regulated money pool and at least $104 million was available through the regulated money pool subject to reduction for borrowings by AmerenCIPS or Ameren Services. Additionally, the Registrant has a lease agreement that provides for the financing of nuclear fuel. At June 30, 2001, the maximum amount that could be financed under the agreement was $120 million. Cash used in financing activities for the six months ended June 30, 2001, included redemptions under the lease for nuclear fuel of $64 million, offset by $3 million of issuances. At June 30, 2001, $53 million was financed under the lease. During the course of Ameren's resource planning, several alternatives, in addition to the Missouri and Venice plant capacity additions described above, are being considered to satisfy anticipated regulatory load requirements for 2001 and beyond for the Registrant, AmerenCIPS and AmerenEnergy Resources Company (Resources Company), the Ameren subsidiary which holds its nonregulated generation operations. The Registrant has purchased 500 megawatts of capacity and energy for the summer of 2001 (450 megawatts from AmerenEnergy Marketing Company (Marketing Company), a subsidiary of Resources Company). Alternatives being considered for the summer of 2002 and beyond include the purchase of capacity and energy, among other things. The Registrant is reviewing three combustion turbine generating units, which had been planned for commercial operation in 2004 and 2005 by Resources Company, to determine if they can be used by the Registrant instead of Resources Company, in order to fulfill the Registrant's generating capacity needs. At this time, management is unable to predict which course of action it will pursue to satisfy these requirements and their ultimate impact on the Registrant's financial position, results of operations or liquidity. In May 2001, the Missouri Public Service Commission (MoPSC) filed pleadings with the Federal Energy Regulatory Commission (FERC) and the SEC relating to the Registrant's agreement to purchase 450 megawatts of capacity and energy from Marketing Company. The Missouri Office of Public Counsel (OPC) also filed pleadings with the FERC in this matter. The MoPSC's FERC pleading was filed in a proceeding initiated by Marketing Company for approval of its power sales agreement with the Registrant. Such pleading requested the FERC to reject Marketing Company's proposed market based rates alleging concerns about affiliate abuse and the overall competitiveness of the market and requested the FERC to set for hearing the appropriate level of cost-based rates, or in the alternative, set for hearing whether Marketing Company has demonstrated that its proposed market-based rates will be just and reasonable. In its pleading, the OPC submitted similar comments. In June 2001, the FERC issued an order which accepted the power sales agreement (with minor modifications), without hearing or suspension, and rejected the pleadings of the MoPSC and the OPC. In July 2001, the MoPSC filed with the FERC a request for clarification of its June 2001 order in the following two respects: (1) that it does not insulate the power sales agreement from a finding of invalidity by the SEC under PUHCA and (2) that it does not preempt the MoPSC from inquiring into the reasonableness of the Registrant's decision to enter into the agreement. To date, the FERC has not responded to the MoPSC's request for clarification. Under the terms of the FERC's June 2001 order, the power sales agreement became effective June 1, 2001. The MoPSC's SEC pleading requests an investigation into the contractual relationship between the Registrant, Marketing Company and AmerenEnergy Generating Company (Generating Company), another subsidiary of Resources Company, in the context of the 450 megawatt power sales agreement and requests that the SEC find that such relationship violates a provision of PUHCA which requires state utility commission approval of power sales contracts between an electric utility company and an affiliated exempt wholesale generator, like Generating Company. In this case, the MoPSC's approval of the power sales agreement was not requested under PUHCA because Generating Company is not a party to the agreement. As a remedy, the MoPSC proposes that the SEC require the Registrant to contract directly with Generating Company and submit such contract to the MoPSC for review. The SEC has not responded to this matter to date. At this time, management is unable to predict the outcome of these proceedings or the ultimate impact on the Registrant's future financial position, results of operation or liquidity. The Registrant, in the ordinary course of business, explores opportunities to reduce its costs in order to remain competitive in the marketplace. Areas where the Registrant focuses its review include, but are not limited to, labor 5 costs and fuel supply costs. In the labor area, over the past two years, the Registrant has reached agreements with all of the Registrant's major collective bargaining units which will permit it to manage its labor costs and practices effectively in the future. The Registrant also explores alternatives to effectively manage the size of its workforce. These alternatives include utilizing hiring freezes, outsourcing and offering employee separation packages. In the fuel supply area, the Registrant explores alternatives to effectively manage its overall fuel costs. These alternatives include diversifying fuel sources for use at the Registrant's fossil power plants, as well as restructuring or terminating existing contracts with suppliers. Certain of these cost reduction alternatives could result in additional investments being made at the Registrant's power plants in order to utilize different types of coal, or could require nonrecurring payments of employee separation benefits or nonrecurring payments to restructure or terminate an existing fuel contract with a supplier. Management is unable to predict which (if any), and to what extent, these alternatives to reduce its overall cost structure will be executed. Management is unable to determine the impact of these actions on the Registrant's future financial position, results of operations or liquidity. RATE MATTERS On June 30, 2001, the Registrant's experimental alternative regulation plan (the Plan) for its Missouri electric customers expired (see Note 2 under Notes to Financial Statements for further information about the Plan). With the Plan's expiration, on July 2, 2001, the MoPSC staff filed with the MoPSC an excess earnings complaint against the Registrant that proposes to reduce the Registrant's annual electric revenues ranging from $213 million to $250 million. Factors contributing to the MoPSC staff's recommendation include return on equity (ROE), revenues and customer growth, depreciation rates and other cost of service expenses. The ROE incorporated into the MoPSC staff's recommendation ranges from 9.04 percent to 10.04 percent. Evidentiary hearings on the MoPSC staff's recommendation will be conducted before the MoPSC. To date, hearings have not been scheduled. The MoPSC is not bound by the MoPSC staff's recommendation. Depending on the outcome of the MoPSC's decision, further appeals in the courts may be warranted. As a result, a final decision on this matter may not occur until 2002. The Registrant is preparing to vigorously contest the MoPSC staff's recommendation in proceedings before the MoPSC. At this time, the Registrant can not predict the outcome of this complaint proceeding, or its impact on the Registrant's financial position, results of operations or liquidity; however, the impact could be material. In the interim, the Registrant expects to continue negotiations with all pertinent parties with the intent to continue with a form of incentive regulation similar to the Plan. The Registrant can not predict the outcome of these negotiations and their impact on the Registrant's financial position, results of operations or liquidity. See Note 2 under Notes to Financial Statements for further discussion of Rate Matters. ELECTRIC INDUSTRY RESTRUCTURING Certain states are considering proposals or have adopted legislation that will promote competition at the retail level. During 2000 and in early 2001, deregulation laws established in the state of California, coupled with high energy prices, increasing demands for power by users in that state, transmission constraints, and limited generation resources, among other things, negatively impacted several major electric utilities in that state. Federal and state regulators and legislators have proposed and implemented, in part, different courses of action to attempt to address these issues. The Registrant does not maintain utility operations in the state of California, nor does it provide energy directly to utilities in that state. At this time, the Registrant is uncertain what impact, if any, changes in deregulation laws will have on future federal and state deregulation laws (including the state of Missouri), which could directly impact the Registrant's future financial position, results of operations or liquidity. Illinois In December 1997, the Governor of Illinois signed the Electric Service Customer Choice and Rate Relief Law of 1997 (the Illinois Law) providing for electric utility restructuring in Illinois. This legislation introduces competition into the supply of electric energy in Illinois. The Illinois Law, among other things, requires the phasing-in through 2002 of retail direct access, which allows customers to choose their electric generation supplier. The phase-in of retail direct access began on October 1, 1999, with large commercial and industrial customers principally comprising the initial group. The remaining commercial and industrial customers in Illinois were offered choice on December 31, 2000. Commercial and 6 industrial customers in Illinois represent approximately 7 percent of the Registrant's total sales. As of June 30, 2001, the impact of retail direct access on the Registrant's financial condition, results of operations or liquidity was immaterial. Retail direct access will be offered to residential customers on May 1, 2002. Missouri During the legislative session that ended in May 2001, the Registrant was participating in discussions with the Missouri legislature regarding legislation that would not restructure the electric industry in Missouri, but would allow utilities to transfer generation assets to an affiliated generating company. In addition, the legislation would have allowed the State's largest nonresidential customers to choose their electric supplier, among other things. No electric industry legislation was passed during the legislative session. Midwest ISO and Alliance RTO In the fourth quarter of 2000, the Registrant announced its intention to withdraw from the Midwest ISO and to join the Alliance Regional Transmission Organization (Alliance RTO), and recorded a pretax charge to earnings of $17 million ($10 million after taxes), which related to the Registrant's estimated obligation under the Midwest ISO agreement for costs incurred by the Midwest ISO, plus estimated exit costs. During first quarter 2001, the FERC conditionally approved the formation, including the rate structure, of the Alliance RTO, and the Registrant announced that it had signed an agreement to join the Alliance RTO. Also in the first quarter 2001, in a proceeding before the FERC, the Alliance RTO and the Midwest ISO reached an agreement that would enable the Registrant to withdraw from the Midwest ISO and to join the Alliance RTO. In April 2001, this settlement agreement was certified by the Administrative Law Judge of the FERC and submitted to the FERC Commissioners for approval. The settlement agreement was approved by the FERC in May 2001. The Registrant's withdrawal from the Midwest ISO remains subject to MoPSC approval. Additional regulatory approvals of the SEC, FERC, MoPSC and the Illinois Commerce Commission may be required in connection with various transactions involving the Alliance RTO relating to its organization, capitalization and the possible transfer of transmission assets. Such approvals, if required, will be sought at the appropriate times. The Alliance RTO is expected to be operational by the end of 2001. At this time, the Registrant is unable to determine the impact that its withdrawal from the Midwest ISO and its participation in the Alliance RTO will have on its future financial condition, results of operation or liquidity. ACCOUNTING MATTERS In January 2001, the Registrant implemented Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities". The impact of that adoption resulted in the Registrant recording a cumulative effect charge of $5 million after taxes to the income statement, and a cumulative adjustment of $8 million after income taxes to other comprehensive income (OCI), which reduced stockholder's equity. (See Note 4 under Notes to Financial Statements for further information.) In June 2001, the Derivatives Implementation Group (DIG), a committee of the Financial Accounting Standards Board (FASB) responsible for providing guidance on the implementation of SFAS 133, reached a conclusion regarding the appropriate accounting treatment of certain types of energy contracts under SFAS 133. Specifically, the DIG concluded that power purchase or sales agreements (both forward contracts and option contracts) may meet an exception for normal purchases and sales accounting treatment if certain criteria are met. At this time, the Registrant is evaluating the impact of the DIG's decision to determine its effect on the Registrant's future financial condition, results of operations, or liquidity upon application. The DIG is currently reviewing the accounting treatment for fuel contracts that combine a forward contract and a purchased option contract. The DIG has not reached a conclusion on whether or not these contracts qualify under the scope exception in SFAS 133 for normal purchases and sales. The Registrant is unable to predict when this issue will be ultimately resolved and the impact that the resolution will have on the Registrant's future financial condition, results of operations or liquidity; however, it could be material. In July 2001, the FASB issued SFAS No. 141, "Business Combinations," SFAS 142, "Goodwill and Other Intangible Assets," and SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 141 requires business combinations to be accounted for under the purchase method of accounting, which requires one party in the transaction to be identified as the acquiring enterprise and for that party to record the assets and liabilities of the acquired enterprise at fair market value rather than historical cost. It prohibits use of the pooling-of-interests method of accounting for business combinations. SFAS 141 is effective for all business combinations initiated after June 30, 2001, or transactions completed using the purchase method after June 30, 2001. SFAS 142 requires goodwill recorded in the financial statements to be tested for impairment at least annually, rather than amortized over a fixed 7 period, with impairment losses recorded in the income statement. SFAS 142 is effective for all fiscal years beginning after December 15, 2001. SFAS 143 requires an entity to record a liability and corresponding asset representing the present value of legal obligations associated with the retirement of tangible, long-lived assets. SFAS 143 is effective for fiscal years beginning after June 15, 2002. SFAS 141 and SFAS 142 are not expected to have a material effect on the Registrant's financial position, results of operations or liquidity upon adoption. At this time, the Registrant is unable to determine the impact of SFAS 143 on its financial position, results of operations or liquidity upon adoption. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Market risk represents the risk of changes in value of a physical asset or a financial instrument, derivative or non-derivative, caused by fluctuations in market variables (e.g. interest rates, equity prices, commodity prices, etc.). The following discussion of Ameren's, including the Registrant's, risk management activities includes "forward-looking" statements that involve risks and uncertainties. Actual results could differ materially from those projected in the "forward-looking" statements. Ameren handles market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, Ameren and the Registrant also face risks that are either non-financial or non-quantifiable. Such risks principally include business, legal, operational, and credit risk and are not represented in the following analysis. Ameren's risk management objective is to optimize its physical generating assets within prudent risk parameters. Risk management policies are set by a Risk Management Steering Committee, which is comprised of senior-level Ameren officers. Interest Rate Risk The Registrant is exposed to market risk through changes in interest rates through its issuance of both long-term and short-term variable-rate debt and fixed-rate debt, and commercial paper. The Registrant manages its interest rate exposure by controlling the amount of these instruments it holds within its total capitalization portfolio and by monitoring the effects of market changes in interest rates. If interest rates increase one percentage point in 2002, as compared to 2001, the Registrant's interest expense would increase by approximately $5 million, and net income would decrease by approximately $3 million. This amount has been determined using the assumptions that the Registrant's outstanding variable-rate debt and commercial paper, as of June 30, 2001, continued to be outstanding throughout 2002, and that the average interest rates for these instruments increased one percentage point over 2001. The estimate does not consider the effects of the reduced level of potential overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no change in the Registrant's financial structure. Commodity Price Risk The Registrant is exposed to changes in market prices for natural gas, fuel and electricity. Several techniques are utilized to mitigate the Registrant's risk, including utilizing derivative financial instruments. A derivative is a contract that has its value dependent on, or derived from, the value of some underlying asset. The derivative financial instruments that the Registrant uses (primarily forward contracts, futures contracts and option contracts) are dictated by risk management policies. With regard to its natural gas utility business, the Registrant's exposure to changing market prices is in large part mitigated by the fact that the Registrant has purchased gas adjustment clauses (PGAs) in place in both its Missouri and Illinois jurisdictions. The PGA allows the Registrant to pass on to its customers its prudently incurred costs of natural gas. Ameren has a subsidiary, AmerenEnergy Fuels and Services Company, a wholly owned subsidiary of Resources Company, which is responsible for providing fuel procurement and gas supply services on behalf of Ameren's operating subsidiaries, and for managing fuel and natural gas price risks. Fixed price forward contracts, as well as futures and options, are all instruments, which may be used to manage these risks. The majority of the Registrant's fuel supply contracts are physical forward contracts. Since the Registrant does not have a provision similar to the PGA for its electric operations, the Registrant has entered into several long-term contracts with various suppliers to purchase coal and nuclear fuel to manage its exposure to fuel prices. All of the required coal for the Registrant's 8 coal plants has been acquired at fixed prices for 2001. In addition, at least 80 percent of the coal requirements through 2005 are covered by long-term contracts. The Registrant has recently experienced some delays in its coal deliveries due to certain transportation and operating constraints in the system. The Registrant is working closely with the transportation companies and monitoring its operating practices in order to maintain adequate levels of coal inventory for future operating purposes. With regard to the Registrant's exposure to commodity price risk for purchased power and excess electricity sales, Ameren has a subsidiary, AmerenEnergy, Inc., (AmerenEnergy), which has as its primary responsibility managing market risks associated with changing market prices for electricity purchased and sold on behalf of the Registrant. Although the Registrant cannot completely eliminate the effects of elevated prices and price volatility, its strategy is designed to minimize the effect of these market conditions on the results of operations. The Registrant's gas procurement strategy includes procuring natural gas under a portfolio of agreements with price structures, including fixed price, indexed price and embedded price hedges such as caps and collars. The Registrant's strategy also utilizes physical assets through storage, operator and balancing agreements to minimize price volatility. The Registrant's electric marketing strategy is to extract additional value from its generation facilities by selling energy in excess of needs for term sales and purchasing energy when the market price is less than the cost of generation. The Registrant's primary use of derivatives has been limited to transactions that are expected to reduce price risk exposure for the Registrant. Equity Price Risk The Registrant maintains trust funds, as required by the Nuclear Regulatory Commission and Missouri and Illinois state laws, to fund certain costs of nuclear decommissioning. As of June 30, 2001, these funds were invested primarily in domestic equity securities, fixed-rate, fixed-income securities, and cash and cash equivalents. By maintaining a portfolio that includes long-term equity investments, the Registrant is seeking to maximize the returns to be utilized to fund nuclear decommissioning costs. However, the equity securities included in the Registrant's portfolio are exposed to price fluctuations in equity markets, and the fixed-rate, fixed-income securities are exposed to changes in interest rates. The Registrant actively monitors its portfolio by benchmarking the performance of its investments against certain indices and by maintaining, and periodically reviewing, established target allocation percentages of the assets of its trusts to various investment options. The Registrant's exposure to equity price market risk is, in large part, mitigated due to the fact that the Registrant is currently allowed to recover its decommissioning costs in its electric rates. SAFE HARBOR STATEMENT Statements made in this Form 10-Q which are not based on historical facts, are "forward-looking" and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such "forward-looking" statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions and financial performance. In connection with the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the Registrant is providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed elsewhere in this report and in the Annual Report on Form 10-K for the fiscal year ended December 31, 2000, and in subsequent securities filings, could cause results to differ materially from management expectations as suggested by such "forward-looking" statements: the effects of regulatory actions, including changes in regulatory policy; changes in laws and other governmental actions; the impact on the Registrant of current regulations related to the phasing-in of the opportunity for some customers to choose alternative energy suppliers in Illinois; the effects of increased competition in the future, due to, among other things, deregulation of certain aspects of the Registrant's business at both the state and federal levels; the effects of withdrawal from the Midwest ISO and membership in Alliance RTO; future market prices for fuel and purchased power, electricity, and natural gas, including the use of financial instruments; average rates for electricity in the Midwest; wholesale pricing for electricity; business and economic conditions; the impact of the adoption of new accounting standards; interest rates; weather conditions; fuel availability; generation plant construction, installation and performance; the impact of current environmental regulations on utilities and generating companies and the expectation that more stringent requirements will be introduced over time, which could potentially have a negative financial effect; monetary and fiscal policies; future wages and employee benefits costs; cost and availability of transmission capacity for the energy generated by the Registrant's generating facilities or required to satisfy energy sales made by the Registrant; and legal and administrative proceedings. 9 UNION ELECTRIC COMPANY BALANCE SHEET UNAUDITED (Thousands of Dollars, Except Shares)
June 30, December 31, ASSETS 2001 2000 - ------ --------------- ---------------- Property and plant, at original cost: Electric $9,616,855 $9,449,275 Gas 245,147 236,139 Other 37,062 37,140 --------------- ---------------- 9,899,064 9,722,554 Less accumulated depreciation and amortization 4,684,187 4,571,292 --------------- ---------------- 5,214,877 5,151,262 Construction work in progress: Nuclear fuel in process 84,528 117,789 Other 207,049 111,527 --------------- ---------------- Total property and plant, net 5,506,454 5,380,578 --------------- ---------------- Investments and other assets: Nuclear decommissioning trust fund 187,210 190,625 Other 73,513 65,811 --------------- ---------------- Total investments and other assets 260,723 256,436 --------------- ---------------- Current assets: Cash and cash equivalents 5,209 19,960 Accounts receivable - trade (less allowance for doubtful accounts of $4,159 and $6,251, respectively) 317,141 277,947 Other accounts and notes receivable 36,941 28,216 Intercompany notes receivable 177,010 255,570 Materials and supplies, at average cost - Fossil fuel 67,869 52,155 Other 83,465 82,161 Other 13,043 16,757 --------------- ---------------- Total current assets 700,678 732,766 --------------- ---------------- Regulatory assets: Deferred income taxes 601,203 599,973 Other 140,134 146,373 --------------- ---------------- Total regulatory assets 741,337 746,346 --------------- ---------------- Total Assets $7,209,192 $7,116,126 =============== ================ CAPITAL AND LIABILITIES - ----------------------- Capitalization: Common stock, $5 par value, 150,000,000 shares authorized - 102,123,834 shares outstanding $510,619 $510,619 Other paid-in capital, principally premium on common stock 701,896 701,896 Retained earnings 1,333,187 1,358,137 Accumulated other comprehensive income (3,610) - --------------- ---------------- Total common stockholder's equity 2,542,092 2,570,652 Preferred stock not subject to mandatory redemption 155,197 155,197 Long-term debt 1,844,779 1,760,439 --------------- ---------------- Total capitalization 4,542,068 4,486,288 --------------- ---------------- Current liabilities: Accounts and wages payable 263,616 293,511 Accumulated deferred income taxes 23,131 30,325 Taxes accrued 166,749 86,125 Other 152,183 196,127 --------------- ---------------- Total current liabilities 605,679 606,088 --------------- ---------------- Accumulated deferred income taxes 1,339,547 1,315,109 Accumulated deferred investment tax credits 132,320 132,922 Regulatory liability 142,091 148,643 Other deferred credits and liabilities 447,487 427,076 -------------- ---------------- Total Capital and Liabilities $7,209,192 $7,116,126 ============== ================
See Notes to Financial Statements. 10 UNION ELECTRIC COMPANY STATEMENT OF INCOME UNAUDITED (Thousands of Dollars)
Three Months Ended Six Months Ended Twelve Months Ended June 30, June 30, June 30, ----------------------- ---------------------- ----------------------- 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- OPERATING REVENUES: Electric $765,032 $664,416 $1,361,897 $1,183,529 $2,768,364 $2,554,173 Gas 18,046 18,095 87,282 60,172 156,351 94,446 Other 203 - 310 - 310 - ---------- ---------- ----------- ----------- ----------- ------------ Total operating revenues 783,281 682,511 1,449,489 1,243,701 2,925,025 2,648,619 OPERATING EXPENSES: Operations Fuel and purchased power 261,338 179,176 480,639 351,614 857,537 718,731 Gas 11,422 9,849 56,998 32,448 106,073 56,560 Other 132,283 120,668 262,734 225,393 537,640 446,697 --------- --------- ----------- ---------- ----------- ----------- 405,043 309,693 800,371 609,455 1,501,250 1,221,988 Maintenance 100,475 80,400 158,980 132,660 276,350 261,555 Depreciation and amortization 69,616 67,337 138,438 134,403 274,411 265,342 Income taxes 48,217 60,872 79,229 89,484 216,545 239,273 Other taxes 53,311 50,196 103,175 97,911 214,724 202,584 ---------- ---------- ----------- ----------- ------------ ----------- Total operating expenses 676,662 568,498 1,280,193 1,063,913 2,483,280 2,190,742 OPERATING INCOME 106,619 114,013 169,296 179,788 441,745 457,877 OTHER INCOME AND (DEDUCTIONS): Allowance for equity funds used during construction 2,218 1,600 3,823 2,829 6,292 5,111 Miscellaneous, net 1,991 2,662 9,028 5,541 19,933 14,474 ----------- ----------- ------------ ----------- ------------ ---------- Total other income and (deductions) 4,209 4,262 12,851 8,370 26,225 19,585 INCOME BEFORE INTEREST CHARGES 110,828 118,275 182,147 188,158 467,970 477,462 INTEREST CHARGES: Interest 29,910 33,548 60,465 66,014 123,733 124,014 Allowance for borrowed funds used during construction (1,540) (2,125) (3,825) (3,944) (8,193) (7,480) ---------- ----------- ----------- ----------- ----------- ----------- Net interest charges 28,370 31,423 56,640 62,070 115,540 116,534 INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 82,458 86,852 125,507 126,088 352,430 360,928 ---------- ----------- ---------- ------------ ----------- ----------- CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF INCOME TAXES - - (4,848) - (4,848) - ---------- ----------- ------------ ------------ ---------- ----------- NET INCOME 82,458 86,852 120,659 126,088 347,582 360,928 PREFERRED STOCK DIVIDENDS 2,205 2,205 4,409 4,409 8,817 8,817 ---------- ----------- ------------ ------------ ---------- ----------- NET INCOME AFTER PREFERRED STOCK DIVIDENDS $80,253 $84,647 $116,250 $121,679 $338,765 $352,111 ========== =========== ============ ============ ========== ===========
See Notes to Financial Statements. 11 UNION ELECTRIC COMPANY STATEMENT OF CASH FLOWS UNAUDITED (Thousands of Dollars)
Six Months Ended June 30, -------------------- 2001 2000 ---- ---- Cash Flows From Operating: Net income $120,659 $126,088 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effect of change in accounting principle 4,848 - Depreciation and amortization 132,369 128,429 Amortization of nuclear fuel 12,497 18,342 Allowance for funds used during construction (7,648) (6,773) Deferred income taxes, net 14,508 6,725 Deferred investment tax credits, net (602) (2,925) Changes in assets and liabilities: Receivables, net (47,919) (89,935) Materials and supplies (17,018) 15,462 Accounts and wages payable (29,895) (46,124) Taxes accrued 80,624 59,656 Other, net (36,850) (47,586) ----------- ----------- Net cash provided by operating activities 225,573 161,359 Cash Flows From Investing: Construction expenditures (252,478) (166,283) Allowance for funds used during construction 7,648 6,773 Nuclear fuel expenditures (12,620) (8,449) Intercompany notes receivable 78,560 (3,420) ----------- ----------- Net cash used in investing activities (178,890) (171,379) Cash Flows From Financing: Dividends on common stock (141,200) (138,150) Dividends on preferred stock (4,409) (4,409) Redemptions - Nuclear fuel lease (64,122) (3,933) Long-term debt - (186,500) Issuances - Nuclear fuel lease 2,497 5,656 Long-term debt 145,800 221,650 ----------- ----------- Net cash used in financing activities (61,434) (105,686) Net change in cash and cash equivalents (14,751) (115,706) Cash and cash equivalents at beginning of year 19,960 117,308 ----------- ----------- Cash and cash equivalents at end of period $ 5,209 $ 1,602 =========== =========== Cash paid during the periods: Interest (net of amount capitalized) $53,480 $58,958 Income taxes, net $31,272 $69,868
See Notes to Financial Statements. 12 UNION ELECTRIC COMPANY STATEMENT OF COMMON STOCKHOLDER'S EQUITY UNAUDITED (Thousands of Dollars) Six Months Ended Year Ended June 30, 2001 December 31, 2000 --------------------- ------------------- Common stock $ 510,619 $ 510,619 Other paid-in capital 701,896 701,896 Retained earnings Beginning balance 1,358,137 1,221,167 Net income 120,659 353,011 Common stock dividends (141,200) (207,224) Preferred stock dividends (4,409) (8,817) --------------------- ------------------- 1,333,187 1,358,137 Accumulated other comprehensive income Beginning balance - - Change in current period (3,610) - --------------------- ------------------- (3,610) - --------------------- ------------------- Total common stockholder's equity $ 2,542,092 $ 2,570,652 ===================== =================== Comprehensive income, net of tax Net income $ 120,659 $ 353,011 Cumulative effect of accounting change, net of taxes (7,881) - Unrealized net gain on derivative hedging instruments 4,271 - --------------------- ------------------- $ 117,049 $ 353,011 ===================== =================== See Notes to Financial Statements. 13 UNION ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS (UNAUDITED) June 30, 2001 Note 1 - Summary of Significant Accounting Policies Basis of Presentation Union Electric Company (AmerenUE or the Registrant) is a subsidiary of Ameren Corporation (Ameren), a holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA). Ameren is the parent company of the following operating subsidiaries: the Registrant, Central Illinois Public Service Company (AmerenCIPS), and AmerenEnergy Generating Company, a wholly owned subsidiary of AmerenEnergy Resources Company. Both Ameren and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Registrant is a public utility engaged principally in the generation, transmission, distribution and sale of electric energy and the purchase, distribution, transportation and sale of natural gas in the states of Missouri and Illinois. Contracts among the Registrant and other Ameren subsidiaries--dealing with jointly-owned generating facilities, interconnecting transmission lines, and the exchange of electric power--are regulated by the Federal Energy Regulatory Commission (FERC) or the Securities and Exchange Commission (SEC). Administrative support services are provided to the Registrant by a separate Ameren subsidiary, Ameren Services Company (Ameren Services). The Registrant serves 1.2 million electric and 125,000 gas customers in a 24,500 square-mile area of Missouri and Illinois, including Metropolitan St. Louis. The Registrant also has a 40 percent interest in Electric Energy, Inc. (EEI), which is accounted for under the equity method of accounting. EEI owns and/or operates electric generating and transmission facilities in Illinois that supply electric power primarily to a uranium enrichment plant located in Paducah, Kentucky. Interim Financial Statements Financial statement note disclosures, normally included in financial statements prepared in conformity with generally accepted accounting principles, have been omitted in this Form 10-Q pursuant to the Rules and Regulations of the SEC. However, in the opinion of the Registrant, the disclosures contained in this Form 10-Q are adequate to make the information presented not misleading. See Notes to Financial Statements included in the 2000 Form 10-K for information relevant to the financial statements contained in this Form 10-Q, including information as to the significant accounting policies of the Registrant. In the opinion of the Registrant, the interim financial statements filed as part of this Form 10-Q reflect all adjustments, consisting only of normal recurring adjustments, necessary for a fair statement of the results for the periods presented. Reclassifications Certain reclassifications have been made to prior years' financial statements to conform with 2001 reporting. Factors Affecting Business Due to the effect of weather on sales and other factors which are characteristic of public utility operations, financial results for the periods ended June 30, 2001 and 2000, are not necessarily indicative of trends for any three-month, six-month or 12-month period. Note 2 - Regulatory Matters Missouri In July 1995, the Missouri Public Service Commission (MoPSC) approved an agreement establishing contractual obligations involving the Registrant's Missouri retail electric rates. Included was a three-year experimental alternative regulation plan (the Original Plan) that ran from July 1, 1995 through June 30, 1998, which provided that earnings in those years in excess of a 12.61 percent regulatory return on equity be shared equally between customers and stockholders, and earnings above a 14 percent regulatory return 14 on equity be credited to customers. The formula for computing the credit used twelve-month results ending June 30, rather than calendar year earnings. A new three-year experimental alternative regulation plan (the New Plan) was included in the joint agreement authorized by the MoPSC in its February 1997 order approving the merger of the Registrant and CIPSCO Incorporated that formed Ameren. Like the Original Plan, the New Plan requires that earnings over a 12.61 percent regulatory return on equity up to a 14 percent regulatory return on equity be shared equally between customers and stockholders. The New Plan also returns to customers 90 percent of all earnings above a 14 percent regulatory return on equity up to a 16 percent regulatory return on equity. Earnings above a 16 percent regulatory return on equity are credited entirely to customers. The New Plan ran from July 1, 1998 through June 30, 2001. During the three months ended June 30, 2001, the Registrant reduced the estimated total credit for the plan year ended June 30, 2001 that the Registrant expects to pay its Missouri electric customers by $25 million. In total, the Registrant has recorded an estimated credit of $40 million as of June 30, 2001 for the plan year ended June 30, 2001, compared to an estimated $35 million credit recorded as of June 30, 2000, for the plan year ended June 30, 2000. These credits were reflected as a reduction in electric revenues. The final amount of the credit will depend on several factors, including the Registrant's earnings for 12 months ended June 30, 2001. With the New Plan's expiration on June 30, 2001, on July 2, 2001, the MoPSC staff filed with the MoPSC an excess earnings complaint against the Registrant that proposes to reduce the Registrant's annual electric revenues ranging from $213 million to $250 million. Factors contributing to the MoPSC staff's recommendation include return on equity (ROE), revenues and customer growth, depreciation rates and other cost of service expenses. The ROE incorporated into the MoPSC staff's recommendation ranges from 9.04 percent to 10.04 percent. Evidentiary hearings on the MoPSC staff's recommendation will be conducted before the MoPSC. To date, hearings have not been scheduled. The MoPSC is not bound by the MoPSC staff's recommendation. Depending on the outcome of the MoPSC's decision, further appeals in the courts may be warranted. As a result, a final decision on this matter may not occur until 2002. The Registrant is preparing to vigorously contest the MoPSC staff's recommendation in proceedings before the MoPSC. At this time, the Registrant can not predict the outcome of this complaint proceeding, or its impact on the Registrant's financial position, results of operations or liquidity; however, the impact could be material. In the interim, the Registrant expects to continue negotiations with all pertinent parties with the intent to continue with a form of incentive regulation similar to the New Plan. The Registrant can not predict the outcome of these negotiations and their impact on the Registrant's financial position, results of operations or liquidity. Midwest ISO and Alliance RTO In the fourth quarter of 2000, the Registrant announced its intention to withdraw from the Midwest Independent System Operator (Midwest ISO) and to join the Alliance Regional Transmission Organization (Alliance RTO), and recorded a pretax charge to earnings of $17 million ($10 million after taxes), which related to the Registrant's estimated obligation under the Midwest ISO agreement for costs incurred by the Midwest ISO, plus estimated exit costs. During first quarter 2001, the FERC conditionally approved the formation, including the rate structure, of the Alliance RTO, and the Registrant announced that it had signed an agreement to join the Alliance RTO. Also in first quarter 2001, in a proceeding before the FERC, the Alliance RTO and the Midwest ISO reached an agreement that would enable the Registrant to withdraw from the Midwest ISO and to join the Alliance RTO. In April 2001, this settlement agreement was certified by the Administrative Law Judge of the FERC and submitted to the FERC Commissioners for approval. The settlement agreement was approved by the FERC in May 2001. The Registrant's withdrawal from the Midwest ISO remains subject to MoPSC approval. Additional regulatory approvals of the SEC, FERC, MoPSC and the Illinois Commerce Commission may be required in connection with various transactions involving the Alliance RTO relating to its organization, capitalization and the possible transfer of transmission assets. Such approvals, if required, will be sought at the appropriate times. The Alliance RTO is expected to be operational by the end of 2001. At this time, the Registrant is unable to determine the impact that its withdrawal from the Midwest ISO and its participation in the Alliance RTO will have on its future financial condition, results of operation or liquidity. 15 Note 3 - Related Party Transactions The Registrant has transactions in the normal course of business with other Ameren subsidiaries. These transactions are primarily comprised of power purchases and sales and services received or rendered. Intercompany receivables included in other accounts and notes receivable were approximately $27 million and $20 million, respectively, as of June 30, 2001 and December 31, 2000. Intercompany payables included in accounts and wages payable totaled approximately $94 million and $27 million, respectively, as of June 30, 2001 and December 31, 2000. Also, the Registrant has the ability to borrow up to approximately $488 million from Ameren, AmerenCIPS or Ameren Services through a regulated money pool agreement. The total amount available to the Registrant at any given time from the regulated money pool is reduced by the amount of borrowings by AmerenCIPS or Ameren Services but increased to the extent AmerenCIPS or Ameren Services have surplus funds and the availability of other external borrowing sources. The regulated money pool was established to coordinate and provide for certain short-term cash and working capital requirements of the Registrant, AmerenCIPS and Ameren Services and is administered by Ameren Services. Interest is calculated at varying rates of interest depending on the composition of internal and external funds in the regulated money pool. For the three months and six months ended June 30, 2001, the average interest rate for the regulated money pool was 4.38 percent and 4.94 percent, respectively. Intercompany interest income for the quarters ended June 30, 2001 and 2000 was approximately $2 million and $3 million, respectively. For the six-month periods ended June 30, 2001 and 2000, intercompany interest income was approximately $5 million for each period. For the 12-month periods ended June 30, 2001 and 2000, intercompany interest income was approximately $11 million and $8 million, respectively. As of June 30, 2001, the Registrant had outstanding intercompany receivables of $177 million and at least $104 million was available through the regulated money pool subject to reduction for borrowings by AmerenCIPS or Ameren Services. Note 4 - Derivative Financial Instruments Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for Derivative Instruments and Hedging Activities" became effective on January 1, 2001. SFAS 133 established accounting and reporting standards for derivative financial instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS 133 requires recognition of all derivatives as either assets or liabilities on the balance sheet measured at fair value. The intended use of derivatives and their designation as either a fair value hedge or a cash flow hedge determines when the gains or losses on the derivatives are to be reported in earnings and when they are reported as a component of other comprehensive income (OCI) in stockholder's equity. In accordance with the transition provisions of SFAS 133, the Registrant recorded a cumulative effect charge of $5 million after income taxes to the income statement, comprised of $1 million for ineffective portion of cash flow hedges and $4 million for discontinued hedges. The Registrant also recorded a cumulative effect adjustment of $8 million after income taxes, representing the effective portion of designated cash flow hedges, to OCI, which reduced stockholder's equity. The Registrant expects that by the end of 2001 it will reclassify to earnings all of the transition adjustment that was recorded in accumulated OCI. Gains and losses on derivatives that arose prior to the initial application of SFAS 133 and that were previously deferred as adjustments of the carrying amount of hedged items were not adjusted and were not included in the transition adjustments described above. All derivatives are recognized on the balance sheet at their fair value. On the date that the Registrant enters into a derivative contract, it designates the derivative as (1) a hedge of the fair value of a recognized asset or liability or an unrecognized firm commitment (a "fair value" hedge); (2) a hedge of a forecasted transaction or the variability of cash flows that are to be received or paid in connection with a recognized asset or liability (a "cash flow" hedge); or (3) an instrument that is held for trading or non-hedging purposes (a "non-hedging" instrument). The Registrant reevaluates its classification of individual derivative transactions daily. The Registrant designates or de-designates derivative transactions as hedges based on many factors including changes in expectations of economic generation availability and changes in projected sales commitments. Changes in the fair value of derivatives are captured and reported based on the anticipated use of the derivative. If a derivative is designated as a cash flow hedge, the effective 16 portion will not be reflected in the income statement. If the derivative is subsequently designated as a non-hedging instrument, any further change in fair value will be reflected in the income statement, with any previously deferred change in fair value remaining in accumulated OCI until the indicated delivery period. If, on the other hand, the derivative had been designated as a non-hedging transaction and subsequently designated as a cash flow hedge, the initial change in fair value between the transaction date and the hedge designation date will be recorded in income, and the effective portion of any further change will be deferred in OCI. Changes in the fair value of derivatives designated as fair value hedges and changes in the fair value of the hedged asset or liability that are attributable to the hedged risk (including changes that reflect losses or gains on firm commitments) are recorded in current-period earnings. Any hedge ineffectiveness (which represents the amount by which the changes in the fair value of the derivative exceed the changes in the fair value of the hedged item) is recorded in current-period earnings. Changes in the fair value of derivative trading and non-hedging instruments are reported in current-period earnings. The Registrant utilizes derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits. The Registrant's risk management objective is to optimize the return from its physical generating assets, while managing exposures to volatile energy commodity prices and emission allowances within prudent risk management policies, which are established by a Risk Management Steering Committee (RMSC) comprised of senior-level Ameren officers. Price fluctuations in natural gas, fuel and electricity cause (1) an unrealized appreciation or depreciation of the Registrant's firm commitments to purchase when purchase prices under the firm commitment are compared with current commodity prices; (2) market values of fuel and natural gas inventories or purchased power to differ from the cost of those commodities under the firm commitment; and (3) actual cash outlays for the purchase of these commodities to differ from anticipated cash outlays. The derivatives that the Registrant uses to hedge these risks are dictated by risk management policies and include forward contracts, futures contracts, options and swaps. Ameren primarily uses derivatives to optimize the value of its physical and contractual positions. Ameren continually assesses its supply and delivery commitment positions against forward market prices and internally forecast forward prices and modifies its exposure to market, credit and operational risk by entering into various offsetting transactions. In general these transactions serve to reduce price risk for the Registrant. Additionally, the Registrant is authorized to engage in certain transactions that serve to increase the organization's exposure to price, credit and operational risk for expected gains. All transactions are continuously monitored and valued by the RMSC to assure compliance with Ameren policies. The RMSC employs a variety of risk measurement techniques and position limits including value at risk, credit value at risk, stress testing, effectiveness testing along with qualitative measures to establish transaction parameters and measure transaction compliance. By using derivative financial instruments, the Registrant is exposed to credit risk and market risk. Credit risk is the risk that the counterparty might fail to fulfill its performance obligations under contractual terms. Credit risk management is based upon consideration and measurement of four factors: (1) accounts receivable; (2) mark to market; (3) probability of default; and (4) the recovery rate of the defaulted position that is likely to be recovered. The Registrant manages its credit (or repayment) risk in derivative instruments by (1) using both portfolio limits, i.e. no more than prescribed dollar amounts exposed to companies within various credit categories as well as limiting exposures to individual companies; (2) monitoring the financial condition of its counterparties; and (3) enhancing credit quality through contractual terms such as netting, required collateral postings, letters of credit and parental guaranties. Market risk is the risk that the value of a financial instrument might be adversely affected by a change in commodity prices. The Registrant manages this risk by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken as mentioned above. The following is a summary of the Registrant's risk management strategies and the effect of these strategies on the Registrant's financial statements. Cash Flow Hedges The Registrant routinely enters into forward purchase and sales contracts for electricity based on forecasted levels of excess economic generation. The amount of excess economic generation varies throughout the year and is monitored by the RMSC. The contracts typically cover a period of twelve months or less. The 17 purpose of these contracts is to hedge against possible price fluctuations in the spot market for the period covered under the contracts. The Registrant formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives designated as cash flow hedges to specific forecasted transactions. The Registrant also formally assesses (both at hedge's inception and on an ongoing basis) whether the derivatives used in hedging transactions have historically been highly effective in offsetting changes in the cash flows of hedged items and whether those derivatives are expected to remain highly effective in future periods. For the three months and six months ended June 30, 2001, the net loss, which represented the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, as well as the reversal of amounts previously recorded in the transition adjustment due to transactions going to delivery, was immaterial. All components of each derivative's gain or loss were included in the assessment of hedge effectiveness. As of June 30, 2001, all $4 million of the deferred net losses on derivative instruments accumulated in other comprehensive income are expected to be reversed during the next twelve months. The derivative losses will be reversed upon delivery of the commodity being hedged. Other Derivatives The Registrant enters into option transactions to manage the Registrant's positions in sulfur dioxide (SO2) allowances. In addition, the Registrant enters into option transactions to manage the Registrant's coal purchasing prices and to manage the cost of electricity by selling puts at prices below the marginal cost of generation. These transactions are treated as non-hedge transactions under SFAS 133; therefore, the net change in the market value of SO2 options is recorded as electric revenues and the net change in the market value of coal options is recorded as fuel and purchased power in the statement of income. Other As of June 30, 2001, the Registrant has recorded the fair value of derivative financial instrument assets of $16 million in Other Assets and derivative financial instrument liabilities of $29 million in Other Deferred Credits and Liabilities. The Registrant has entered into fixed-price forward contracts for the purchase of coal and natural gas. While these contracts meet the definition of a derivative under SFAS 133, the Registrant records these transactions as normal purchases and normal sales because the contracts are expected to result in physical delivery. 18 PART II - OTHER INFORMATION ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. At the annual meeting of stockholders of the Registrant held on April 24, 2001, the following matter was presented to the meeting for a vote and the results of such voting are as follows: Item (1) Election of Directors.
Non-Voted Name For Withheld Brokers ---- ---- --------- --------- Paul A. Agathen 104,019,088 16,738 0 Warner L. Baxter.................. 104,018,488 17,346 0 Donald E. Brandt.................. 104,020,527 17,132 0 Charles W. Mueller................ 104,019,194 15,688 0 Gary L. Rainwater................. 104,019,084 16,742 0
ITEM 5. OTHER INFORMATION. Any stockholder proposal intended for inclusion in the proxy material for the Registrant's 2002 annual meeting of stockholders must be received by the Registrant by November 30, 2001. In addition, under the Registrant's By-Laws, stockholders who intend to submit a proposal in person at an annual meeting, or who intend to nominate a director at a meeting, must provide advance written notice along with other prescribed information. In general, such notice must be received by the Secretary of the Registrant not later than 60 nor earlier than 90 days prior to the first anniversary of the preceding year's annual meeting. For the Registrant's 2002 annual meeting of stockholders, written notice of any in-person stockholder proposal or director nomination must be received not later than February 23, 2002 or earlier than January 24, 2002. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. (a)(i) Exhibits. 12 - Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements, 12 Months Ended June 30, 2001. (a)(ii) Exhibits Incorporated by Reference. 10.1 - Alliance Agreement establishing the Alliance Independent Transmission System Operator, Inc., Alliance Transmission Company, Inc. and Alliance Transmission Company, LLC and Amendment to admit AmerenCIPS and AmerenUE (June 30, 2001 Ameren Corporation Form 10-Q, Exhibit 10.1). (b) Reports on Form 8-K. None. Note: Reports of Ameren Corporation on Forms 8-K, 10-Q and Form 10-K are on file with the SEC under File Number 1-14756. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. 19 UNION ELECTRIC COMPANY (Registrant) By /s/ Donald E. Brandt -------------------------------- Donald E. Brandt Senior Vice President Finance and Corporate Services (Principal Financial Officer) Date: August 14, 2001 Exhibit 12 UNION ELECTRIC COMPANY COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED STOCK DIVIDEND REQUIREMENTS
12 Months Ended Year Ended December 31, June 30, -------------------------------------------------------------------------- 1996 1997 1998 1999 2000 2001 ---- ---- ---- ---- ---- ---- Thousands of Dollars Except Ratios Net Income $304,876 $301,655 $320,070 $349,252 $353,011 $347,582 Add- Extraordinary items net of tax - 26,967 - - - - ---------- --------- --------- --------- --------- --------- Net income from continuing operations 304,876 328,622 320,070 349,252 353,011 347,582 ---------- --------- --------- --------- --------- --------- Taxes based on income 196,210 199,763 212,554 226,696 224,149 216,541 ---------- --------- --------- --------- --------- --------- Net income before income taxes 501,086 528,385 532,624 575,948 577,160 564,123 ---------- --------- --------- --------- --------- --------- Add- fixed charges: Interest on long term debt 120,547 125,705 124,766 117,899 121,763 116,115 Other interest 7,828 9,299 1,660 (1,342) 4,219 4,331 Rentals 3,458 3,727 3,416 3,899 3,928 3,610 Amortization of net debt premium, discount, expenses and losses 4,269 3,672 3,522 3,421 3,300 3,286 ---------- --------- --------- --------- --------- --------- Total fixed charges 136,102 142,403 133,364 123,877 133,210 127,342 ---------- --------- --------- --------- --------- --------- Earnings available for fixed charges 637,188 670,788 665,988 699,825 710,370 691,465 ========== ========= ========= ========= ========= ========= Ratio of earnings to fixed charges 4.68 4.71 4.99 5.64 5.33 5.42 ========== ========= ========= ========= ========= ========= Earnings required for preferred dividends: Preferred stock dividends 13,249 8,817 8,817 8,817 8,817 8,817 Adjustment to pre-tax basis 7,363 4,257 4,649 4,544 4,439 4,362 ---------- --------- --------- --------- --------- --------- 20,612 13,074 13,466 13,361 13,256 13,179 Fixed charges plus preferred stock dividend requirements 156,714 155,477 146,830 137,238 146,466 140,521 ========== ========= ========= ========= ========= ========= Ratio of earnings to fixed charges plus preferred stock dividend requirements 4.06 4.31 4.53 5.09 4.85 4.92 ========== ========= ========= ========= ========= =========
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