The accompanying notes are an integral part of these consolidated financial statements.
In May 2005, UE sold an interest in assets to CIPS in exchange for a subordinated promissory note from CIPS, and UE
contributed an interest in assets to Ameren Corporation. See Note 3 for further details.
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY (Consolidated)
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
AMEREN ENERGY GENERATING COMPANY (Consolidated)
CILCORP INC. (Consolidated)
CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)
ILLINOIS POWER COMPANY (Consolidated)
COMBINED NOTES TO FINANCIAL STATEMENTS
(Unaudited)
June 30, 2005
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company registered with the SEC under the PUHCA. Ameren’s primary asset is the common stock of its subsidiaries. Ameren’s 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 are dependent on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below.
| · | 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 and prior to May 2, 2005, in Illinois. See Note 3 - Rate and Regulatory Matters for information regarding the May 2005 transfer of UE’s Illinois electric and natural gas transmission and distribution businesses to CIPS and the addition of a large new electric customer in June 2005. |
| · | 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. See Note 3 - Rate and Regulatory Matters for information regarding the May 2005 transfer of Genco’s 10 CTs located in Pinckneyville and Kinmundy, Illinois to UE. |
| · | CILCO, or Central Illinois Light Company, also known as AmerenCILCO, is a subsidiary of CILCORP (a holding company) and operates a rate-regulated electric transmission and distribution business, a primarily non-rate-regulated electric generation business, 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 acquired IP on September 30, 2004, from Dynegy. See Note 2 - Acquisitions and Note 8 - Related Party Transactions for further information. |
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 through UE and Resources Company, which each own 40% of EEI. Ameren consolidates EEI for financial reporting purposes, while UE reports EEI under the equity method.
The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. As the acquisition of IP occurred on September 30, 2004, Ameren’s Consolidated Statements of Income and Cash Flows for the period ended June 30, 2004, do not reflect IP’s results of operations or financial position. See Note 2 - Acquisitions for further information on the accounting for the IP acquisition. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
In addition to presenting results of operations and earnings amounts in total, certain information in this report is expressed in cents per share. These amounts reflect factors that directly impact Ameren’s earnings. We believe this per share information is useful because it better enables 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 diluted shares.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) 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 for a full year. Certain reclassifications have been made to prior year’s financial statements to conform to 2005 reporting. These statements should be read in conjunction with the financial statements and the notes thereto included in the Ameren Companies’ combined 2004 Annual Report on Form 10-K.
As part of the acquisition of IP on September 30, 2004, Ameren “pushed down” the effects of purchase accounting to
the financial statements of IP. Accordingly, IP’s postacquistion financial statements reflect a new basis of accounting, and separate financial statement amounts are presented for preacquisition (predecessor) and postacquisition (successor) periods, separated by a bold black line. As a result of the acquisition of IP, certain reclassifications have been made to make IP prior-year financial statements conform to our current presentation.
Earnings Per Share
There were no material differences between Ameren’s basic and diluted earnings per share for the three months and six months ended June 30, 2005 and 2004, due to an immaterial number of stock options outstanding.
Asset Retirement Obligations
Asset retirement obligations at Ameren and UE increased by $6 million for the quarter ended June 30, 2005, to reflect the accretion of obligations to their present value. Additionally, Ameren and Genco’s asset retirement obligations increased by $1.5 million during the quarter ended June 30, 2005, due to revisions in estimated future cash flows to retire a Genco ash pond. Increases to CILCORP’s and CILCO’s asset retirement obligations due to accretion were immaterial during this period. Substantially all of this accretion was recorded as an increase to regulatory assets.
Accounting Changes and Other Matters
FIN No. 47, “Accounting for Conditional Asset Retirement Obligations"
FSP SFAS No. 106-2 - “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”
In May 2004, the FASB issued FSP SFAS 106-2, which provides guidance on accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 for employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Ameren, UE, CIPS, Genco, CILCORP and CILCO elected to adopt FSP SFAS 106-2 during the second quarter ended June 30, 2004, retroactive to January 1, 2004. The effect of the federal subsidy provided by this Medicare Prescription Drug Act was a reduction of various components of Ameren’s and principally UE’s net periodic postretirement benefit costs.
Predecessor IP’s adoption of FSP SFAS 106-2 on July 1, 2004, had no impact on IP’s results of operations, financial position, or liquidity because its drug benefit was not actuarially equivalent to the drug benefit under Medicare Part D.
Interchange Revenues
The following table presents the interchange revenues included in Operating Revenues - Electric for the three months and six months ended June 30, 2005 and 2004:
| | Three Months | | Six Months | |
| | 2005 | | 2004 | | 2005 | | 2004 | |
Ameren(a) | $ | 154 | | $ | 87 | | $ | 267 | | $ | 187 | |
| UE | | 129 | | | 71 | | | 226 | | | 155 | |
| CIPS | | 8 | | | 10 | | | 17 | | | 19 | |
| Genco | | 67 | | | 36 | | | 109 | | | 75 | |
| CILCORP | | 11 | | | 9 | | | 26 | | | 20 | |
| CILCO | | 11 | | | 9 | | | 26 | | | 20 | |
IP(b) | | (c | ) | | (c | ) | | (c | ) | | (c | ) |
| (a) | Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP. Includes interchange revenues for EEI of $8 million and $15 million for the three months and six months ended June 30, 2005, respectively (2004 - $16 million and $30 million, respectively). |
| (b) | 2004 amount represents predecessor information. |
| (c) | Less than $1 million. |
Purchased Power
The following table presents the purchased power expenses included in Operating Expenses - Fuel and Purchased Power for the three months and six months ended June 30, 2005 and 2004. See Note 8 - Related Party Transactions for further information on affiliate purchased power transactions.
| | Three Months | | Six Months | |
| | | 2005 | | | 2004 | | | 2005 | | | 2004 | |
Ameren(a) | $ | 250 | | $ | 77 | | $ | 455 | | $ | 152 | |
| UE | | 66 | | | 49 | | | 104 | | | 102 | |
| CIPS | | 105 | | | 79 | | | 191 | | | 159 | |
| Genco | | 68 | | | 34 | | | 117 | | | 74 | |
| CILCORP | | 12 | | | 8 | | | 22 | | | 30 | |
| CILCO | | 12 | | | 8 | | | 22 | | | 30 | |
IP(b) | | 165 | | | 154 | | | 322 | | | 305 | |
| (a) | Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP. |
| (b) | 2004 amount represents predecessor information. |
Excise Taxes
Excise taxes reflected on Missouri electric, Missouri gas, and Illinois gas customer bills are imposed on us. They are recorded gross in Operating Revenues and Taxes Other than Income Taxes on each company’s statements of income. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer. They are recorded as tax collections payable and included in Taxes Accrued. The following table presents excise taxes recorded in Operating Revenues and Taxes Other than Income Taxes for the three months and six months ended June 30, 2005 and 2004:
| | Three Months | | Six Months | |
| | 2005 | | 2004 | | 2005 | | 2004 | |
Ameren(a) | $ | 41 | | $ | 31 | | $ | 81 | | $ | 65 | |
| UE | | 28 | | | 27 | | | 50 | | | 51 | |
| CIPS | | 2 | | | 2 | | | 7 | | | 7 | |
| CILCORP | | 3 | | | 2 | | | 5 | | | 7 | |
| CILCO | | 3 | | | 2 | | | 5 | | | 7 | |
IP(b) | | 8 | | | 5 | | | 19 | | | 17 | |
| (a) | Excludes 2004 amounts for IP. |
| (b) | 2004 amount represents predecessor information. |
NOTE 2 - ACQUISITIONS
IP and EEI
On September 30, 2004, Ameren completed the acquisition of all the common stock and 662,924 shares of preferred stock of IP and an additional 20% ownership interest in EEI from subsidiaries of Dynegy. Ameren acquired IP to complement its existing Illinois gas and electric operations. The purchase included IP’s rate-regulated electric and natural gas transmission and distribution business serving 600,000 electric and 415,000 gas customers in areas contiguous to our existing Illinois utility service territories. With the acquisition, IP became an Ameren subsidiary operating as AmerenIP.
The total transaction value was $2.3 billion, including the assumption of $1.8 billion of IP debt and preferred stock and consideration, including transaction costs, of $440 million in cash, net of $51 million cash acquired and a working capital adjustment of $5 million received from Dynegy in February 2005 pursuant to the terms of the stock purchase agreement. Ameren placed $100 million of the cash portion of the purchase price in a six-year escrow account pending resolution of certain contingent environmental obligations of IP and other Dynegy affiliates for which Ameren was provided indemnification by Dynegy. On July 27, 2005, the conditions for release of the escrow account were satisfied and Dynegy was remitted the $100 million. In addition, this transaction included a fixed-price capacity power supply agreement for IP’s annual purchase in 2005 and 2006 of 2,800 megawatts of electricity from DYPM. This agreement is expected to supply about 70% of IP’s electric customer requirements during those two years. The remaining 30% of IP’s power needs in 2005 and 2006 will be supplied by other companies through contracts and open market purchases. In the event that suppliers are unable to supply the electricity required by existing agreements, IP would be forced to find alternative suppliers to meet its load requirements, thus exposing itself to market price risk, which could have a material impact on Ameren’s and IP’s results of operations, financial position, or liquidity.
Ameren funded this acquisition with the issuance of new Ameren common stock. Ameren issued an aggregate of 30 million common shares in February 2004 and July 2004, which generated net proceeds of $1.3 billion. Proceeds from these issuances were used to finance the cash portion of the purchase price and to reduce IP debt assumed as part of this transaction and to pay related premiums.
In December 2004, 230 IP employees accepted a voluntary separation opportunity, which provides an enhanced separation benefit and extended medical and dental benefits. Employees who accepted the voluntary separation opportunity will leave IP throughout 2005 as business needs warrant. These voluntary separations are consistent with Ameren’s plan for the integration of IP and conditions in the ICC order approving the acquisition, which relate to the realization of administrative synergies from the acquisition. As of June 30, 2005, estimated separation costs of $25 million were deferred as a regulatory asset for future recovery from customers, which is also consistent with the ICC order.
Ameren is completing its valuations of the acquired net assets and liabilities of IP and EEI, including third-party valuations of property and plant, intangible assets, pension and other postretirement benefit obligations, and contingent obligations. As a result, the allocation of the purchase price is subject to further adjustment. The fair value of IP’s power supply agreements, including the fixed-price capacity power supply agreement with DYPM, recorded at the acquisition date resulted in a net liability of $109 million (June 30, 2005 - $67 million). This amount is being amortized through December 31, 2006. In addition, IP recorded a fair value adjustment, resulting in a net asset of $20 million (June 30, 2005 - $12 million), for IP’s power supply agreement with EEI that expires at the end of 2005. The excess of the purchase price for IP’s common stock and preferred stock over net
assets acquired was allocated preliminarily to goodwill in the amount of $303 million, net of future tax benefits. No specifically identifiable intangible assets have been identified. For income tax purposes, we expect that a portion of the purchase price will be allocated to goodwill and that such portion will be deducted ratably over a 15-year period. Goodwill decreased by $17 million since December 31, 2004, primarily because of adjustments to property and plant, income tax accounts and accrued severance and relocation expenses, partially offset by adjustments to regulatory assets and net assets for IP’s power supply agreement with EEI. The following table presents the estimated fair values of the assets acquired and liabilities assumed at the date of Ameren’s acquisition of IP.
| Current assets | $ | 370 | |
| Property and plant | | 1,974 | |
| Investments and other noncurrent assets | | 394 | |
| Goodwill | | 303 | |
| Total assets acquired | | 3,041 | |
| Current liabilities | | 228 | |
| Long-term debt, including current maturities | | 1,982 | |
| Accrued pension and other postretirement liabilities | | 244 | |
| Other non-current liabilities | | 208 | |
| Total liabilities assumed | | 2,662 | |
| Preferred stock assumed | | 13 | |
| Net assets acquired | $ | 366 | |
The following unaudited pro forma financial information presents a summary of Ameren’s consolidated results of operations for the three months and six months ended June 30, 2004, as if the acquisition of IP had been completed at the beginning of 2004, including pro forma adjustments, which are based upon preliminary estimates, to reflect the allocation of the purchase price to the acquired net assets. The pro forma financial information does not include cost savings that may result from the combination of Ameren with IP.
2004 | | Three Months | | | Six Months | |
| Operating revenues | $ | 1,473 | | $ | 3,149 | |
| Net income | | 149 | | | 290 | |
| Earnings per share - basic | | 0.77 | | | 1.50 | |
- diluted | | 0.77 | | | 1.50 | |
This pro forma information is not necessarily indicative of the results of operations as they would have been had the transaction been effected on the assumed date, nor is it an indication of trends for future results.
IP’s Note Receivable from Former Affiliate of $2.3 billion was eliminated as of September 30, 2004, and prior to Ameren’s acquisition of IP to meet the conditions of the closing.
The portion of the total transaction value attributable to Ameren’s acquisition of Dynegy’s 20% ownership interest in EEI now held by Resources Company was $125 million. This transaction was accounted for as a step acquisition. The excess of the purchase price for this ownership interest over 20% of the fair value of EEI’s net assets acquired has been preliminarily allocated to property and plant ($55 million) and emission allowances ($48 million), partially offset by a net liability for power supply agreements ($25 million) and a reduction to net deferred tax assets ($31 million). The remaining excess was allocated to goodwill in the amount of $65 million, subject to change based on our final valuation. Goodwill increased by $11 million since December 31, 2004, due to adjustments to property and plant and the net liability for power supply agreements, partially offset by adjustments to both emission allowances and income tax accounts, resulting from the refinement of the third-party valuation of EEI’s net assets, which is in the process of being finalized.
NOTE 3 - RATE AND REGULATORY MATTERS
Below is a summary of significant regulatory proceedings. With respect to pending matters, we are unable to predict the ultimate outcome of these regulatory proceedings, the timing of the final decisions of the various agencies or the impact on our results of operations, financial position, or liquidity.
Intercompany Transfer of Illinois Service Territory and Electric Generating Facilities
Illinois Service Territory Transfer
On May 2, 2005, following the receipt of all required regulatory approvals, UE completed the transfer of its Illinois-based electric and natural gas utility businesses, including its Illinois-based distribution assets and certain of its transmission assets, at a net book value of $133 million to CIPS. UE’s electric generating facilities and a certain insignificant amount of its electric transmission and communication facilities in Illinois were not part of the transfer. Pursuant to the asset transfer agreement, UE transferred 50 percent of the assets directly to CIPS in consideration for a CIPS subordinated promissory note in the principal amount of approximately $67 million and 50 percent of the assets by means of a dividend in kind to Ameren, followed by a capital contribution by Ameren to CIPS. With the completion of this transfer, UE no longer operates as a public utility subject to ICC regulation.
In February 2005, the MoPSC issued an order approving the transfer and clarified its order in March 2005. The MoPSC’s order, as clarified, included the following principal conditions:
| · | The order allows UE to recover in rates up to 6% of unknown UE generation-related liabilities associated with the generation that was formerly allocated to UE’s Illinois service territory if UE can show that the benefits of the transfer of the Illinois service territory outweigh these costs in future rate cases. |
| · | The order requires an amendment to the joint dispatch agreement among UE, Genco and CIPS to declare that margins on short-term power sales will be divided based |
| | on generation output as opposed to load. In testimony filed by UE with the MoPSC to support the transfer, UE indicated this amendment would have provided UE with additional annual margins and Genco with reduced annual margins of $7 million to $24 million based on certain assumptions and historical results. The ultimate impact of any modifications to the joint dispatch agreement will be determined by future native load demand, the availability of electric generation from UE and Genco and market prices, among other things, but such impact could be material. This reduction to Genco’s margins is expected to be mitigated by margins received from additional power sales by Genco (through Marketing Company) to CIPS to serve the transferred UE Illinois-based electric utility business through the end of 2006 under the current power supply contracts. The increased allocation of short-term power sales margins to UE would have the effect of lowering the revenue required to be collected through rates the next time electric rates are adjusted. |
| · | The MoPSC also ordered that UE may complete the transfer prior to receipt of all regulatory approvals necessary to effectuate the required amendment to the joint dispatch agreement based on UE’s commitment that for ratemaking purposes the joint dispatch agreement amendment should be deemed to be made by UE as of the date the transfer is closed. In the event that the regulatory approvals for the amendment are not obtained, this commitment would result in just the allocation of these additional margins to UE for determining the revenue requirements in the ratemaking process, with no impact on Genco’s margins. |
| · | The order requires that, in a future rate case, revenues UE could have received for incremental energy transfers under the joint dispatch agreement resulting from the service territory transfer be imputed based on market prices unless UE can show the benefits of the transfer of the Illinois service territory outweigh the difference between the market prices and the actual cost-based charges for such incremental energy transfers. |
Electric Generating Facilities Transfer
On May 2, 2005, following the receipt of all required regulatory approvals, Genco completed the transfer to UE of its 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois, at a net book value of $241 million. This transfer completed the remainder of UE’s commitment under the 2002 Missouri electric rate case settlement, which required the addition of 700 megawatts of generation capacity by June 30, 2006.
The Illinois service territory transfer and the electric generating facilities transfer, discussed above, were accounted for at book value with no gain or loss recognition. Genco used the proceeds from the transfer to reduce borrowings.
Missouri
Noranda Aluminum, Inc. (Noranda)
Following the receipt of all regulatory approvals and satisfaction of all regulatory and other conditions, the tariff by which UE serves Noranda became effective June 1, 2005. UE will serve Noranda under a 15-year agreement to supply approximately 470 megawatts (peak load) electric service (or approximately 5% of UE’s generating capability, including currently committed purchases) to Noranda’s primary aluminum smelter in southeast Missouri.
Illinois
Electric
By 2002, all of the Illinois residential, commercial and industrial customers of UE, CIPS, CILCO and IP had a choice in electric suppliers under the provisions of the Illinois Customer Choice Law. Under the Illinois Customer Choice Law, UE, CIPS, CILCO and IP rates initially were frozen through January 1, 2005. Due to an amendment to the Illinois Customer Choice Law, the rate freeze was extended through January 1, 2007. As a result of this extension, and pursuant to orders of the ICC, CIPS and Marketing Company, and CILCO and AERG, extended their respective power supply agreements through December 31, 2006. See Note 8 - Related Party Transactions for a discussion of these affiliate power supply agreements.
During 2004, the ICC conducted workshops to seek input from interested parties on the framework for retail electric rate determination and generation procurement after the current Illinois electric rate freeze expires on January 1, 2007, and supply contracts expire on December 31, 2006. A report issued by the ICC in late 2004, which outlined a process, among others, that would have CIPS, CILCO and IP procure power through an auction monitored by the ICC, received strong support in the ICC workshops. The form of power supply would meet the full requirements of the utility and the risk of fluctuations in power requirements would be borne by the supplier. In addition, the report noted that many stakeholders, including Ameren, supported a process whereby the price of power resulting from the auction would be the price used to determine the generation component of customer rates. This purchased power would be charged to customers through a direct pass-through mechanism. With regard to the delivery service component of customer rates, it is expected that all Illinois delivery service companies will file rate cases, at which time the delivery service component of customer rates will be updated. Genco and AERG would probably participate in the auction through Marketing
Company, but there is expected to be a limit imposed by the ICC on the maximum amount of power they could supply CIPS, CILCO and IP.
In February 2005, CIPS, CILCO and IP filed with the ICC a proposed process for the generation procurement auction and a rate mechanism to pass generation costs through to customers, among other things, which was consistent with the auction process described above. These proposals are subject to review and approval by the ICC by January 2006. In May 2005, the Illinois Attorney General, the Citizens Utility Board (CUB) and the Environmental Law and Policy Center filed a Motion to Dismiss the proposed procurement auction in the CIPS, CILCO and IP filings. Subsequently, in June 2005, the Administrative Law Judge denied the Motion to Dismiss. The Illinois Attorney General and CUB subsequently appealed the Administrative Law Judge’s ruling to the ICC and this appeal was also denied by the ICC in July 2005.
The ICC Staff and interveners filed testimony regarding our proposed process for the generation procurement auction in June 2005. In its testimony, the ICC Staff continued to support the generation auction process, but sought modifications to aspects of the CIPS, CILCO and IP proposed process for the procurement of power and the passing of these costs through to customers. The Illinois Attorney General and CUB in their testimonies recommended that the ICC initiate a new docket to investigate alternatives to an auction, among other things. CIPS, CILCO and IP filed supplemental testimony in early July. That testimony modified certain aspects of the February proposal and CIPS, CILCO and IP believe the modifications will substantially address issues raised by the ICC staff and certain other interveners. The modifications included changes to the timing of the auction, a limition of 35% on the amount of power any single supplier can provide of any distribution company's expected annual load and allowing suppliers to switch their bids between auctions for similar products.
In early 2005, the Illinois legislature held hearings regarding the framework for retail rate determination and generation procurement. We cannot predict what actions, if any, the Illinois legislature will take, or whether the ICC will approve our proposals for generation procurement or electric rate determination.
Gas
In May 2005, the ICC issued an order awarding IP increases in annual natural gas delivery rates of $11 million. In the order approving Ameren’s acquisition of IP, the ICC prohibited IP from filing for any proposed increase in gas delivery rates to be effective prior to January 1, 2007, beyond this recently authorized gas delivery rate increase. IP filed an appeal in the appellate court for the Third District in Illinois regarding certain immaterial disallowances issued by the ICC in its May 2005 order. Ameren sought indemnification from Dynegy with regard to the disallowances under the stock purchase agreement covering Ameren’s acquisition of IP from Dynegy, and in July 2005 Dynegy paid to Ameren $8.3 million in full settlement of this indemnification claim. Under the terms of the settlement, IP will retain the benefits of any successful appeal of the May 2005 ICC order with no refund obligation to Dynegy.
Federal
Hydroelectric License Renewal
In May 2005, UE, the U.S. Department of the Interior and various state agencies reached a settlement agreement which is expected to lead to the FERC’s relicensing of the Osage hydroelectric plant for another 40 years. The settlement must be approved by the FERC, which, together with the relicense, is expected by year-end 2005. The current FERC license expires on February 28, 2006.
NOTE 4 - SHORT-TERM BORROWINGS AND LIQUIDITY
Short-term borrowings have typically consisted of commercial paper issuances and drawings under committed bank credit facilities with maturities generally within 1 to 45 days.
The following table summarizes the short-term borrowing activity and relevant interest rates as of June 30, 2005 and December 31, 2004, respectively:
| | Ameren(a) | UE |
June 30, 2005: | | |
| Short-term borrowings at June 30, 25 | $ 161 | $ 138 |
| Average daily borrowings outstanding during 2005 | 274 | 239 |
| Weighted average interest rate during 2005 | 1.15% | 2.55% |
| Peak short-term borrowings during 2005 | 468 | 424 |
| Peak interest rate during 2005 | 3.52% | 3.45% |
| | Ameren(a) | UE |
December 31, 2004: | | |
| Short-term borrowings at December 31, 2004 | $ 417 | $ 375 |
| Average daily borrowings outstanding during 2004 | 47 | 33 |
| Weighted average interest rate during 2004 | 2.19% | 1.56% |
| Peak short-term borrowings during 2004 | 419 | 375 |
| Peak interest rate during 2004 | 2.97% | 2.40% |
| (a) | Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes amounts for IP prior to September 30, 2004. |
In July 2005, Ameren, UE, CIPS, CILCO, Genco and IP entered into a five-year revolving credit agreement, maturing on July 14, 2010, with various lenders which provides for loans to, and letters of credit issued for, the accounts of Ameren, UE, CIPS, CILCO, Genco and IP in an amount up to $1.15 billion. The entire amount of the facility is available to Ameren; UE may directly borrow under this facility up to $500 million on a short-term 364-day basis; and CIPS, Genco, CILCO and IP may also directly borrow under this facility each up to $150 million and also on a short-term 364-day basis. The interest rates applicable under the facility are based on a Eurodollar rate plus a margin applicable to the particular borrowing company, a competitive rate bid by the lenders, or a rate equal to the higher of JPMorgan Chase Bank, N.A.’s prime rate and the sum of the federal funds effective rate plus 1/2 percent per annum, plus the margin applicable to the particular borrowing company. The credit agreement contains customary terms and conditions (see Indebtedness Provisions and Other Covenants below for financial covenant provisions). The obligations of Ameren, UE, CIPS, Genco, CILCO and IP under this facility are several and not joint. The obligations of UE, CIPS, Genco, CILCO and IP are not guaranteed by any other subsidiary. See Exhibit 10.1 to the Current Report on Form 8-K dated July 15, 2005, for the full agreement.
Also in July 2005, Ameren, as sole borrower, entered into an amended and restated credit agreement which revised its $350 million five-year revolving credit agreement dated as of July 14, 2004. The changes to this facility make the entire amount of commitments available in the form of letters of credit as well as loans, extend the maturity date to July 2010 and conform, as applicable, the affirmative and negative covenants, events of default and representations and warranties to the July 2005 $1.15 billion revolving credit agreement discussed above. See Exhibit 10.2 to the Current Report on Form 8-K, dated July 15, 2005, for the full amended and restated credit agreement.
Upon execution of the new $1.15 billion credit agreement, Ameren terminated its $235 million amended and restated three-year revolving credit agreement, dated as of September 21, 2004, and its $350 million three-year revolving credit agreement dated as of July 14, 2004. In addition, this agreement replaced UE’s bilateral credit agreements in an aggregate amount of $153.5 million, CIPS’ bilateral credit agreements in an aggregate amount of $15 million, CILCO’s bilateral credit agreements in an aggregate amount of $60 million and a bilateral credit agreement of EEI in the amount of $25 million. The Ameren Companies will use the proceeds of any borrowings under this facility to repay any amounts outstanding under these terminated or replaced credit agreements and for general corporate purposes, including for working capital, commercial paper liquidity support and to fund loans under the money pool arrangements. After giving effect to these changes, Ameren currently has $1.5 billion of committed credit facilities consisting of two facilities each maturing in July 2010.
At June 30, 2005, certain of the Ameren Companies had committed bank credit facilities totaling $1 billion, $868 million of which was available for use, subject to applicable regulatory short-term borrowing authorizations, by UE, CIPS, CILCO, IP and Ameren Services through a utility money pool arrangement. All of the $868 million was available for use, subject to applicable regulatory short-term borrowing authorizations, by Ameren directly, by CILCORP through direct short-term borrowings from Ameren, and by most of the non-rate-regulated subsidiaries including, but not limited to, Resources Company, Genco, Marketing Company, AFS, AERG and Ameren Energy, through a non-state-regulated subsidiary money pool agreement. The committed bank credit facilities are used to support our commercial paper programs under which $139 million was outstanding for Ameren and UE at June 30, 2005 (December 31, 2004 - $375 million). Access to credit facilities for the Ameren Companies is subject to reduction based on use by affiliates.
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 between rate-regulated and non-rate-regulated entities. Ameren Services is responsible for operation and administration of the money pool agreements. See Note 8 - Related Party Transactions for a detailed explanation of these money pool arrangements.
In July 2005, CILCO redeemed 11,000 shares of its 5.85% Class A preferred stock at a redemption price of $100 per share plus accrued and unpaid dividends. The redemption satisfied CILCO’s mandatory sinking fund redemption requirement for this series of preferred stock for 2005.
In April 2005, EEI renewed a $20 million bank credit facility, which was scheduled to mature in the second quarter of 2005. The credit facility will now expire in the second quarter of 2006.
Ameren and UE are authorized by the SEC under the PUHCA to have an aggregate of up to $1.5 billion and $1 billion, respectively, of short-term unsecured debt instruments outstanding at any time. The aggregate amount of short-term borrowings outstanding at any time at IP may not exceed $500 million pursuant to authorizations from the ICC and the SEC under the PUHCA. In addition, CIPS, CILCORP and CILCO have the PUHCA authority to have an aggregate of up to $250 million each of short-term unsecured debt instruments outstanding at any time. Genco is authorized by the FERC to have up to $300 million of short-term debt outstanding at any time.
Borrowings under Ameren’s non-state-regulated subsidiary money pool agreement by Genco, Development Company and Medina Valley, each an exempt wholesale generator, are considered investments for purposes of the SEC’s 50% aggregate investment limitation under the PUHCA. Based on Ameren’s aggregate investment in these exempt wholesale generators as of June 30, 2005, the maximum permissible borrowings under Ameren’s non-state-regulated subsidiary money pool pursuant to this limitation for these entities totaled $525 million.
Indebtedness Provisions and Other Covenants
Certain of the Ameren Companies’ bank credit agreements contain provisions which, among other things, place restrictions on the ability to incur liens, sell assets, and merge with other entities. The $1.15 billion July 2005 revolving credit agreement discussed above also contains a provision that limits Ameren’s, UE’s, CIPS’, Genco’s and IP’s total indebtedness to 65% of total capitalization and CILCO’s total indebtedness to 60% of total capitalization pursuant to a calculation set forth in the agreement. The $350 million July 2005 amended and restated credit agreement contains a similar provision only with respect to Ameren. Exceeding these debt levels would result in a default under the credit agreements. As of June 30, 2005, the ratio of total indebtedness to total capitalization (calculated in accordance with this provision) for Ameren, UE, CIPS, Genco, CILCO and IP was 46%, 47%, 42%, 52%, 29% and 44%, respectively (December 31, 2004 - Ameren 50%, UE 44%, CIPS 53%, CILCO ---43%, not applicable for Genco or IP). In addition, these credit agreements contain indebtedness cross-default provisions that could trigger a default under these facilities in the event that any of Ameren’s subsidiaries (subject to the definition in the underlying credit agreements), other than certain project finance subsidiaries, defaults in indebtedness in excess of $50 million. The credit agreements also require us to meet minimum ERISA funding rules.
None of the Ameren Companies’ credit agreements or financing arrangements contains credit rating triggers. One of EEI’s credit agreements contains a credit rating trigger under which a default can occur in the event any of the credit ratings of EEI’s sponsors (UE, CIPS and Kentucky Utilities Company) fall below Baa3 or BBB- by Moody’s and S&P, respectively, and the sponsors do not cover a payment default. At June 30, 2005, the Ameren Companies and EEI were in compliance with their credit agreement provisions and covenants.
NOTE 5 - LONG-TERM DEBT AND EQUITY FINANCINGS
Ameren
Under DRPlus, pursuant to an effective SEC Form S-3 registration statement, and under our 401(k) plans, pursuant to effective SEC Form S-8 registration statements, Ameren issued a total of 1.2 million new shares of common stock in the first six months of 2005 valued at $57 million.
In March 2002, Ameren issued $345 million of adjustable conversion-rate equity security units consisting of $345 million of senior unsecured notes due 2007 and stock purchase contracts. In February 2005, the annual interest rate on these senior unsecured notes was reset to 4.263% through a remarketing process in accordance with and as required by the original terms of the related financing agreements. The proceeds from remarketing the senior unsecured notes were used by the holders of the equity security units to purchase treasury securities to secure their obligations to purchase Ameren common stock on May 15, 2005, pursuant to the stock purchase contracts. Ameren did not receive any proceeds as part of the remarketing. In the remarketing, Ameren purchased $95 million in principal amount of the senior unsecured notes, which were subsequently retired. In May 2005, settlement of the stock purchase contracts resulted in Ameren issuing 7.4 million shares of common stock in exchange for $345 million of proceeds. The adjustable conversion-rate equity security units ceased trading on the New York Stock Exchange before the opening of the market on May 16, 2005.
UE
In July 2005, UE issued, pursuant to its effective September 2003 SEC Form S-3 shelf registration statement, $300 million of 5.30% senior secured notes due August 1, 2037, with interest payable semi-annually on February 1 and August 1 of each year beginning in February 2006. UE received net proceeds of $296 million which were used to repay short-term debt.
In January 2005, UE issued, pursuant to its effective September 2003 SEC Form S-3 shelf registration statement, $85 million of 5.00% senior secured notes due February 1, 2020, with interest payable semi-annually on February 1 and
August 1 of each year beginning in August 2005. UE received net proceeds of $83 million, which were used to repay short-term debt incurred to fund the December 2004 maturity of UE’s $85 million 7.375% first mortgage bonds.
CIPS
In June 2005, $20 million of CIPS’ 6.49% first mortgage bonds matured and were retired.
CILCORP
In May 2005, CILCORP repurchased $5 million in principal amount of its 8.70% senior notes due 2009.
In conjunction with Ameren’s acquisition of CILCORP in January 2003, CILCORP’s long-term debt was recorded at fair value. Amortization related to these fair value adjustments was $2 million (2004 - $2 million) and $4 million (2004 - $4 million) for the three months and six months ended June 30, 2005, respectively, and was included as a reduction to Interest Charges.
IP
In conjunction with Ameren’s acquisition of IP in September 2004, IP’s long-term debt was recorded at fair value. Amortization related to fair value adjustments was $4 million (2004 - less than $1 million) and $9 million (2004 - less than $1 million) for the three months and six months ended June 30, 2005, respectively, and was included as a reduction to Interest Charges.
Indenture Provisions and Other Covenants
The information below represents a summary of the Ameren Companies compliance with indenture provisions and other covenants. See Note 6 - Long-term Debt and Equity Financings in the Ameren Companies combined Annual Report on Form 10-K for the year ended December 31, 2004, for a detailed description of these 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. The following table includes the earnings coverage ratio for interest charges and preferred dividends and bonds and preferred stock issuable for the 12 months ended June 30, 2005, at an assumed interest and dividend rate of 7%.
| | Interest Coverage Ratio | Bonds Issuable(a) | Dividend Coverage Ratio | Preferred Stock Issuable |
| UE | 7.8 | $ 3,781 | 66.4 | $ 2,169 |
| CIPS | 3.2 | 161 | 2.0 | 148 |
| CILCO | 10.1 | 635 | 24.3 | 252 |
| IP | 4.4 | 885 | 2.07 | 406 |
| (a) | Amount of bonds issuable based on meeting required coverable ratios. |
In addition, as of June 30, 2005, UE had $31 million of total retained earnings restricted against payment of common dividends, except those dividends payable in common stock.
Genco’s and CILCORP’s indentures include provisions which require the companies maintain certain debt service coverage and debt to capital ratios in order for the companies to pay dividends, make certain principal or interest payments, make certain loans to affiliates, or to incur additional indebtedness. The following table summarizes these ratios for the 12 months ended June 30, 2005:
| | Required Interest Coverage Ratio | Actual Interest Coverage Ratio | Required Debt to Capital Ratio | Actual Debt to Capital Ratio |
Genco (a) | 1.75 | 5.5 | 60% | 51% |
CILCORP(b) | 2.2 | 2.7 | 67% | 52% |
| (a) | Interest coverage ratio relates to covenants regarding certain dividend, principal and interest payments on certain subordinated intercompany borrowings. The debt to capital ratio relates to a debt incurrence covenant, which also requires an interest coverage ratio of 2.5. |
| (b) | CILCORP must maintain the required interest coverage ratio and debt to capital ratio in order to make any payment of dividends or intercompany loans to affiliates other than to its direct or indirect subsidiaries. |
The ability for the Ameren Companies to issue securities in the future will depend on such tests at that time.
Off-Balance Sheet Arrangements
At June 30, 2005, 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.
NOTE 6 - OTHER INCOME AND DEDUCTIONS
The following table presents Other Income and Deductions for each of the Ameren Companies for the three months and six months ended June 30, 2005 and 2004, respectively:
| | Three Months | | Six Months | |
| | 2005 | | 2004 | | 2005 | | 2004 | |
Ameren:(a) | | | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | | | |
Interest and dividend income | $ | 1 | | $ | 3 | | $ | 2 | | $ | 5 | |
| Allowance for equity funds used during construction | | 3 | | | 1 | | | 7 | | | 4 | |
Other | | 2 | | | - | | | 4 | | | 3 | |
| Total miscellaneous income | $ | 6 | | $ | 4 | | $ | 13 | | $ | 12 | |
| Miscellaneous expense: | | | | | | | | | | | | |
Minority interest in subsidiary | $ | - | | $ | (2 | ) | $ | (1 | ) | $ | (3 | ) |
| Loss on disposition of property | | (2 | ) | | - | | | (2 | ) | | - | |
| Other | | (7 | ) | | (2 | ) | | (7 | ) | | (2 | ) |
Total miscellaneous expense | $ | (9 | ) | $ | (4 | ) | $ | (10 | ) | $ | (5 | ) |
UE: | | | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | | | |
Interest and dividend income | $ | - | | $ | 1 | | $ | - | | $ | 2 | |
Equity in earnings of subsidiary | | 1 | | | 2 | | | 2 | | | 3 | |
Allowance for equity funds used during construction | | 1 | | | 1 | | | 6 | | | 4 | |
Other | | 1 | | | - | | | 3 | | | - | |
| Total miscellaneous income | $ | 3 | | $ | 4 | | $ | 11 | | $ | 9 | |
| Miscellaneous expense: | | | | | | | | | | | | |
Other | $ | (2 | ) | $ | (4 | ) | $ | (4 | ) | $ | (5 | ) |
Total miscellaneous expense | $ | (2 | ) | $ | (4 | ) | $ | (4 | ) | $ | (5 | ) |
CIPS: | | | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | | | |
Interest and dividend income | $ | 4 | | $ | 6 | | $ | 9 | | $ | 13 | |
Total miscellaneous income | $ | 4 | | $ | 6 | | $ | 9 | | $ | 13 | |
| Miscellaneous expense: | | | | | | | | | | | | |
Other | $ | (4 | ) | $ | (1 | ) | $ | (4 | ) | $ | (1 | ) |
Total miscellaneous expense | $ | (4 | ) | $ | (1 | ) | $ | (4 | ) | $ | (1 | ) |
Genco: | | | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | | | |
Other | $ | 1 | | $ | - | | $ | 1 | | $ | - | |
Total miscellaneous income | $ | 1 | | $ | - | | $ | 1 | | $ | - | |
| Miscellaneous expense: | | | | | | | | | | | | |
Other | $ | - | | $ | - | | $ | - | | $ | (1 | ) |
Total miscellaneous expense | $ | - | | $ | - | | $ | - | | $ | (1 | ) |
CILCORP: | | | | | | | | | | | | |
| Miscellaneous expense: | | | | | | | | | | | | |
Other | $ | (3 | ) | $ | (1 | ) | $ | (5 | ) | $ | (2 | ) |
Total miscellaneous expense | $ | (3 | ) | $ | (1 | ) | $ | (5 | ) | $ | (2 | ) |
CILCO: | | | | | | | | | | | | |
| Miscellaneous expense: | | | | | | | | | | | | |
Other | $ | (2 | ) | $ | (2 | ) | $ | (3 | ) | $ | (3 | ) |
Total miscellaneous expense | $ | (2 | ) | $ | (2 | ) | $ | (3 | ) | $ | (3 | ) |
IP:(b) | | | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | | | |
Interest and dividend income | $ | 1 | | $ | 2 | | $ | 2 | | $ | 2 | |
Tilton Lease | | - | | | 3 | | | - | | | 7 | |
Allowance for equity funds used during construction | | 1 | | | - | | | 1 | | | - | |
Gain on disposition of property | | - | | | 1 | | | - | | | 1 | |
Other | | - | | | 1 | | | 1 | | | 2 | |
Total miscellaneous income | $ | 2 | | $ | 7 | | $ | 4 | | $ | 12 | |
| Miscellaneous expense: | | | | | | | | | | | | |
Other | $ | (1 | ) | $ | (1 | ) | $ | (1 | ) | $ | (1 | ) |
Total miscellaneous expense | $ | (1 | ) | $ | (1 | ) | $ | (1 | ) | $ | (1 | ) |
(a) Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP.
(b) 2004 amounts represent predecessor information.
NOTE 7 - DERIVATIVE FINANCIAL INSTRUMENTS
The following table presents balances in certain accounts for cash flow hedges as of June 30, 2005:
| | Ameren(a) | | UE | | CIPS | | Genco | | CILCORP | | CILCO | | IP | |
2005: | | | | | | | | | | | | | | |
| Balance Sheet: | | | | | | | | | | | | | | | | | | | | | |
Other assets | $ | 66 | | $ | 9 | | $ | 16 | | $ | - | | $ | 33 | | $ | 33 | | $ | 5 | |
Other deferred credits and liabilities | | 25 | | | 15 | | | 4 | | | 1 | | | 2 | | | 2 | | | 2 | |
| Accumulated OCI: | | | | | | | | | | | | | | | | | | | | | |
Power forwards(b) | | (1 | ) | | - | | | - | | | (1 | ) | | - | | | - | | | - | |
Interest rate swaps(c) | | 4 | | | - | | | - | | | 4 | | | - | | | - | | | - | |
Gas swaps and futures contracts(d) | | 50 | | | 8 | | | 11 | | | - | | | 29 | | | 29 | | | 3 | |
| (a) | Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations. |
| (b) | Represents the mark-to-market value for the hedged portion of electricity price exposure for periods generally less than one year. Certain contracts designated as hedges of electricity price exposure have terms up to three years. |
| (c) | Represents a gain associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity and the gain in OCI is amortized over a 10-year period that began in June 2002. |
| (d) | Represents a gain associated with natural gas swaps and futures contracts. The swaps are a partial hedge of our natural gas requirements through March 2008. |
The pretax net gain or loss on power forward derivative instruments is included in Operating Revenues - Electric or Operating Expenses - Fuel and Purchased Power at Ameren, UE and Genco. This represents the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, and the reversal of amounts previously recorded in OCI due to transactions going to delivery or settlement, resulting in a less than $1 million loss for Ameren and Genco for the three months ended June 30, 2005 (2004 - $2 million gain for Ameren and a $1 million gain for UE and Genco) and a less than $1 million gain for Ameren and Genco and a less than $1 million loss for UE for the six months ended June 30, 2005 (2004 - $2 million gain for Ameren and a $1 million gain for UE and Genco).
Other Derivatives
The following table represents the net change in market value of option transactions, which are used to manage our positions in SO2 emission allowances and coal. Certain of these transactions are treated as nonhedge transactions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. The net change in the market value of SO2 options is recorded in Operating Revenues - Electric, while the net change in the market value
of coal options is recorded as Operating Expenses - Fuel and Purchased Power.
| | Three Months | Six Months |
Gains (Losses)(a) | 2005 | 2004 | 2005 | 2004 |
SO2 options: | | | | |
Ameren(b) | $ (c) | $ (1) | $ (6) | $ (2) |
UE | $ (c) | $ (4) | $ (1) | $ (7) |
Genco | $ - | $ 3 | $ (5) | $ 5 |
| (a) | Coal option gains and losses were less than $1 million for all periods shown above. |
| (b) | Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP. |
| (c) | Less than $1 million. |
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 Ameren Companies’ combined Form 10-K for the fiscal year ended December 31, 2004. Below are updates to several of these related party transactions as well as additional related party transactions.
Electric Power Supply Agreements
The following table presents the amount of gigawatthour sales under related party electric power supply agreements.
| | Three Months | | Six Months | |
| | 2005 | | 2004 | | 2005 | | 2004 | |
Genco sales to Marketing Company | | 5,196 | | | 4,544 | | | 10,096 | | | 9,465 | |
Marketing Company sales to CIPS | | 2,497 | | | 1,794 | | | 4,553 | | | 3,737 | |
| EEI sales to UE | | 744 | | | 830 | | | 1,441 | | | 1,646 | |
EEI sales to CIPS | | 371 | | | 414 | | | 943 | | | 822 | |
EEI sales to IP | | 381 | | | 438 | | | 794 | | | 868 | |
Joint Dispatch Agreement
UE and Genco jointly dispatch electric generation under an agreement among UE, Genco and CIPS. Each affiliate has the option to serve its load requirements from its own generation first and then each allows access to any available remaining generation to its affiliate at incremental cost. Any excess generation not used by UE or Genco to serve load requirements is sold to third parties through Ameren Energy,
serving as each affiliate’s agent. These third party sales margins are allocated between UE and Genco using the ratio of each company’s load requirements to the companies’ combined load regardless of which company sourced the power. To allocate power costs between UE and Genco, an intercompany sale is recorded, at cost, by the company sourcing the power to the other company. Ameren Energy also acts as agent on behalf of UE and Genco to purchase power when they require it. The joint dispatch agreement can be terminated by either party upon one year’s notice.
Due to the MoPSC order approving the Illinois service territory transfer or future regulatory proceedings, there could be changes to the agreement between UE and Genco to jointly dispatch electric generation or changes to the effect of that agreement on revenues and/or electric margins. Such changes could affect the pricing or availability of power transferred between Genco and UE. Based on operating performance for the past year, such changes would likely result in a transfer of electric margins from Genco to UE. The ultimate impact of any modifications to the joint dispatch agreement will be determined by future native load demand, the availability of electric generation from UE and Genco and market prices, among other things, but such impact could be material. Ameren’s earnings could be affected if electric rates for UE are adjusted by the MoPSC to reflect the provisions of the MoPSC order approving the service territory transfer and/or other changes to the joint dispatch agreement. See Note 3 - Rate and Regulatory Matters to our financial statements in Part 1, Item 1 of this report for a discussion of modifications to the joint dispatch agreement ordered by the MoPSC.
The following table presents the amount of gigawatthour sales under the joint dispatch agreement.
| | Three Months | | Six Months | |
| | 2005 | | 2004 | | 2005 | | 2004 | |
Joint Dispatch Agreement | | | | | | | | | | | | |
UE sales to Genco | | 3,814 | | | 1,799 | | | 6,763 | | | 3,983 | |
Genco sales to UE | | 1,219 | | | 625 | | | 1,816 | | | 1,293 | |
Money Pools
Utility
Through the utility money pool, the pool participants can access any committed credit facilities at Ameren and excess cash at Ameren, UE, CIPS, CILCO and IP. See Note 4 - Short-term Borrowings and Liquidity for amounts available under credit facilities. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings by their affiliates, but increased to the extent the pool participants have surplus funds or other external sources are used to increase the available amounts. The average interest rate for borrowing under the utility money pool for the three months ended June 30, 2005 was 3.0% (2004 - 1.0%) and for the six months ended June 30, 2005 was 2.7% (2004 - 1.0%) .
Non-state-regulated subsidiaries
Through the non-state-regulated subsidiary money pool, pool participants can access committed credit facilities at Ameren and excess cash at Ameren, Genco and other pool participants. See Note 4 - Short-term Borrowings and Liquidity for amounts available under credit facilities. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three months ended June 30, 2005 was 5.5% (2004 - 8.8%) and for the six months ended June 30, 2005 was 6.9% (2004 - 8.8%).
CILCORP has been granted authority by the SEC under the PUHCA to borrow up to $250 million directly from Ameren in a separate arrangement unrelated to the money pools. At June 30, 2005, CILCORP had notes payable under this agreement of $94 million. The interest rate under this agreement is the same as the non-state-regulated subsidiary money pool.
Intercompany Promissory Notes
On May 1, 2005, Genco and CIPS amended certain terms of its subordinated note payable to CIPS by issuing to CIPS an amended and restated subordinated promissory note in the principal amount of approximately $249 million with an interest rate of 7.125% per annum, a 5-year amortization schedule and a maturity date of May 1, 2010. As of June 30, 2005, $197 million was outstanding under this note.
Also on May 1, 2005, the remaining principal balance under Genco’s note payable to Ameren of $34 million was repaid.
On May 2, 2005, CIPS issued to UE a subordinated promissory note in the principal amount of approximately $67 million as consideration for 50% of UE’s Illinois-based utility assets transferred to CIPS on that date. The note bears interest at 4.70% per annum and has a 10-year amortization schedule and a maturity date of May 2, 2010. See Note 3 - Rate and Regulatory Matters for a discussion of this intercompany transfer.
Intercompany Transfer of Illinois Service Territory and Electric Generating Facilities
See Note 3 - Rate and Regulatory Matters for a discussion of the related party transactions engaged in with respect to the intercompany transfer of UE’s Illinois service territory and Genco’s electric generating facilities.
On June 22, 2005, UE purchased an uninstalled 117 megawatt CT and related vendor contract rights from
Development Company for an estimated market price of approximately $25 million. Also on that date, UE purchased wet compression upgrade equipment for this CT and related vendor contract rights from Resources Company for an estimated market price of approximately $1.5 million. UE is constructing these facilities at Venice, Illinois.
Summary of Related Party Transactions
The following tables present the impact of related party transactions on the Ameren Companies’ statements of income based primarily on the transactions discussed above and in Note 14 - Related Party Transactions under Part II, Item 8 of the Ameren Companies’ combined Form 10-K for the fiscal year ended December 31, 2004.
UE
| | Three Months | | Six Months | |
Consolidated Statement of Income | 2005 | | 2004 | | 2005 | | 2004 | |
| Operating revenues from affiliates: | | | | | | | | |
Power supply agreement with EEI | $ | (a | ) | $ | 2 | | $ | (a | ) | $ | 2 | |
Joint dispatch agreement with Genco | | 56 | | | 28 | | | 97 | | | 58 | |
Share of joint dispatch agreement interchange sales | | 74 | | | 42 | | | 129 | | | 95 | |
Gas transportation agreement with Genco | | (a | ) | | (a | ) | | (a | ) | | (a | ) |
Total operating revenues | $ | 130 | | $ | 72 | | $ | 226 | | $ | 155 | |
| Fuel and purchased power expenses from affiliates: | | | | | | | | | | | | |
Power supply agreements: | | | | | | | | | | | | |
EEI | $ | 16 | | $ | 17 | | $ | 30 | | $ | 33 | |
Marketing Company | | 2 | | | 3 | | | 4 | | | 5 | |
Joint dispatch agreement with Genco | | 21 | | | 12 | | | 31 | | | 24 | |
| Total fuel and purchased power expenses | $ | 39 | | $ | 32 | | $ | 65 | | $ | 62 | |
| Other operating expenses: | | | | | | | | | | | | |
| Support service agreements: | | | | | | | | | | | | |
| Ameren Services | $ | 40 | | $ | 38 | | $ | 81 | | $ | 76 | |
| Ameren Energy | | 1 | | | 4 | | | 2 | | | 7 | |
| AFS | | 1 | | | 1 | | | 2 | | | 2 | |
| Total other operating expenses | $ | 42 | | $ | 43 | | $ | 85 | | $ | 85 | |
| Interest expense: | | | | | | | | | | | | |
| Borrowings from money pool | $ | 2 | | $ | 1 | | $ | 2 | | $ | 1 | |
| (a) | Less than $1 million. |
CIPS
| | Three Months | | Six Months | |
Statement of Income | | 2005 | | | 2004 | | | 2005 | | | 2004 | |
| Operating revenues from affiliates: | | | | | | | | | | | | |
| Power supply agreements: | | | | | | | | | | | | |
Marketing Company | $ | 8 | | $ | 8 | | $ | 17 | | $ | 16 | |
| Total operating revenues | $ | 8 | | $ | 8 | | $ | 17 | | $ | 16 | |
| Fuel and purchased power expenses from affiliates: | | | | | | | | | | | | |
| Power supply agreements: | | | | | | | | | | | | |
| Marketing Company | $ | 94 | | $ | 71 | | $ | 170 | | $ | 143 | |
| EEI | | 8 | | | 8 | | | 17 | | | 16 | |
| Total fuel and purchased power expenses | $ | 102 | | $ | 79 | | $ | 187 | | $ | 159 | |
| Other operating expenses: | | | | | | | | | | | | |
| Support service agreements: | | | | | | | | | | | | |
| Ameren Services | $ | 11 | | $ | 12 | | $ | 22 | | $ | 24 | |
| AFS | | 1 | | | - | | | 1 | | | - | |
| Total other operating expenses | $ | 12 | | $ | 12 | | $ | 23 | | $ | 24 | |
| Interest income: | | | | | | | | | | | | |
Note receivable from Genco | $ | 4 | | $ | 6 | | $ | 8 | | $ | 13 | |
Borrowings (advances) related to money pool | | (a | ) | | (a | ) | | (a | ) | | (a | ) |
| (a) | Less than $1 million. |
Genco
| | Three Months | | Six Months | |
Consolidated Statement of Income | 2005 | | 2004 | | 2005 | | 2004 | |
| Operating revenues from affiliates: | | | | | | | | | | | | |
Power supply agreements: | | | | | | | | | | | | |
Marketing Company | $ | 195 | | $ | 168 | | $ | 374 | | $ | 341 | |
EEI | | (a | ) | | 1 | | | (a | ) | | 1 | |
Joint dispatch agreement with UE | | 21 | | | 12 | | | 31 | | | 24 | |
Share of joint dispatch agreement interchange sales | | 46 | | | 22 | | | 78 | | | 49 | |
| Operating lease with Development Company | | 3 | | | 2 | | | 5 | | | 5 | |
Total operating revenues | $ | 265 | | $ | 205 | | $ | 488 | | $ | 420 | |
| Fuel and purchased power expenses from affiliates: | | | | | | | | | | | | |
| Joint dispatch agreement with UE | $ | 56 | | $ | 28 | | $ | 97 | | $ | 58 | |
| Power purchase agreement with Marketing Company | | (a | ) | | (a | ) | | 2 | | | (a | ) |
| Gas transportation agreement with UE | | (a | ) | | (a | ) | | (a | ) | | (a | ) |
| Total fuel and purchased power expenses | $ | 56 | | $ | 28 | | $ | 99 | | $ | 58 | |
| Other operating expenses: | | | | | | | | | | | | |
| Support service agreements: | | | | | | | | | | | | |
Ameren Services | $ | 5 | | $ | 4 | | $ | 10 | | $ | 8 | |
Ameren Energy | | (a | ) | | 3 | | | 1 | | | 4 | |
AFS | | (a | ) | | 1 | | | 1 | | | 1 | |
Total other operating expenses | $ | 5 | | $ | 8 | | $ | 12 | | $ | 13 | |
| Interest expense: | | | | | | | | | | | | |
Borrowings from money pool | $ | 1 | | $ | 3 | | $ | 3 | | $ | 6 | |
Note payable to CIPS | | 4 | | | 6 | | | 8 | | | 13 | |
Note payable to Ameren | | (a | ) | | (a | ) | | 1 | | | 1 | |
| (a) | Less than $1 million. |
CILCORP
| | Three Months | | Six Months | |
Consolidated Statement of Income | 2005 | | 2004 | | 2005 | | 2004 | |
| Operating revenues from affiliates: | | | | | | | | |
| Power supply agreements: | | | | | | | | | | | | |
Bilateral supply agreement with Marketing Company | $ | 6 | | $ | 9 | | $ | 21 | | $ | 19 | |
| Total operating revenues | $ | 6 | | $ | 9 | | $ | 21 | | $ | 19 | |
| Fuel and purchased power expenses from affiliates: | | | | | | | | | | | | |
| Executory tolling agreement with Medina Valley | $ | 8 | | $ | 7 | | $ | 18 | | $ | 17 | |
| Bilateral supply agreement with Marketing Company | | 4 | | | 5 | | | 7 | | | 9 | |
| Total fuel and purchased power expenses | $ | 12 | | $ | 12 | | $ | 25 | | $ | 26 | |
| Other operating expenses: | | | | | | | | | | | | |
| Support services agreements: | | | | | | | | | | | | |
Ameren Services | $ | 9 | | $ | 12 | | $ | 21 | | $ | 25 | |
AFS | | (a | ) | | 1 | | | 1 | | | 1 | |
Total other operating expenses | $ | 9 | | $ | 13 | | $ | 22 | | $ | 26 | |
| Interest expense: | | | | | | | | | | | | |
Note payable to Ameren | $ | 1 | | $ | 1 | | $ | 3 | | $ | 2 | |
Borrowings from money pool | | 1 | | | 1 | | | 2 | | | 2 | |
| (a) | Less than $1 million. |
CILCO
| | Three Months | | Six Months | |
Consolidated Statement of Income | 2005 | | 2004 | | 2005 | | 2004 | |
| Operating revenues from affiliates: | | | | | | | | | | | | |
| Power supply agreements: | | | | | | | | | | | | |
Bilateral supply agreement with Marketing Company | $ | 6 | | $ | 9 | | $ | 21 | | $ | 19 | |
| Total operating revenues | $ | 6 | | $ | 9 | | $ | 21 | | $ | 19 | |
| Fuel and purchased power expenses from affiliates: | | | | | | | | | | | | |
Executory tolling agreement with Medina Valley | $ | 8 | | $ | 7 | | $ | 18 | | $ | 17 | |
| Bilateral supply agreement with Marketing Company | | 4 | | | 5 | | | 7 | | | 9 | |
| Total fuel and purchased power expenses | $ | 12 | | $ | 12 | | $ | 25 | | $ | 26 | |
| | Three Months | | Six Months | |
Consolidated Statement of Income | 2005 | | 2004 | | 2005 | | 2004 | |
| Other operating expenses: | | | | | | | | | | | | |
| Support services agreements: | | | | | | | | | | | | |
Ameren Services | $ | 9 | | $ | 12 | | $ | 21 | | $ | 24 | |
AFS | | (a | ) | | (a | ) | | 1 | | | (a | ) |
Total other operating expenses | $ | 9 | | $ | 12 | | $ | 22 | | $ | 24 | |
| Interest expense: | | | | | | | | | | | | |
Borrowings from money pool | $ | 1 | | $ | 1 | | $ | 2 | | $ | 2 | |
| (a) | Less than $1 million. |
| | | Three Months | | Six Months | |
Consolidated Statement of Income | | 2005 | | 2004(a) | | 2005 | | 2004(a) | |
| Operating revenues from affiliates and former affiliates: | | | | | | | | | |
| Retail electricity sales to DMG | | $ | - | | $ | 1 | | $ | - | | $ | 1 | |
| Retail natural gas sales to DMG | | | - | | | 1 | | | - | | | 3 | |
| Transmission sales to DYPM | | | - | | | 3 | | | - | | | 7 | |
| Interconnection transmission with DYPM | | | - | | | 1 | | | - | | | 1 | |
| Interest income from former affiliates | | | - | | | 43 | | | - | | | 85 | |
Total operating revenues | | $ | - | | $ | 49 | | $ | - | | $ | 97 | |
| Fuel and purchased power expenses from affiliates and former affiliates: | | | | | | | | | | | | | |
| Power supply agreements: | | | | | | | | | | | | | |
| DMG | | $ | - | | $ | 108 | | $ | - | | $ | 232 | |
| EEI | | | 13 | | | 7 | | | 27 | | | 15 | |
| Gas purchased from Dynegy | | | - | | | (b | ) | | - | | | 6 | |
Total fuel and purchased power expenses | | $ | 13 | | $ | 115 | | $ | 27 | | $ | 253 | |
| Other operating expenses: | | | | | | | | | | | | | |
| Support services agreements: | | | | | | | | | | | | | |
| Ameren Services | | $ | 22 | | $ | - | | $ | 22 | | $ | - | |
| AFS | | | 1 | | | - | | | 1 | | | - | |
Services and facilities agreement - Dynegy | | | - | | | 5 | | | - | | | 8 | |
| Total other operating expenses | | $ | 23 | | $ | 5 | | $ | 23 | | $ | 8 | |
| Interest expense (income): | | | | | | | | | | | | | |
Interest expense for IP SPT | | $ | 3 | | $ | 6 | | $ | 6 | | $ | 12 | |
Interest expense on Tilton lease | | | - | | | 4 | | | - | | | 8 | |
Interest income on Tilton lease | | | - | | | (4 | ) | | - | | | (8 | ) |
Advances to money pool | | | (1 | ) | | - | | | (2 | ) | | - | |
| (a) | Represents predecessor information. |
NOTE 9 - COMMITMENTS AND CONTINGENCIES
Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 3 - Rate and Regulatory Matters, Note 14 - Related Party Transactions and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Ameren Companies’ combined Form 10-K for the fiscal year ended December 31, 2004.
Callaway Nuclear Plant
The following table presents insurance coverage at UE’s Callaway nuclear plant at June 30, 2005:
The following table presents insurance coverage at UE’s Callaway nuclear plant at June 30, 2005:
Type and Source of Coverage | Maximum Coverages | | Maximum Assessments for Single Incidents | |
| Public liability: | | | | | | |
| American Nuclear Insurers | $ | 300 | | $ | - | |
| Pool participation | | 10,461 | | | 101 | (a) |
| $ | 10,761 | (b) | $ | 101 | |
| Nuclear worker liability: | | | | | | |
| American Nuclear Insurers | $ | 300 | (c) | $ | 4 | |
| Property damage: | | | | | | |
| Nuclear Electric Insurance Ltd. | $ | 2,750 | (d) | $ | 21 | |
| Replacement power: | | | | | | |
| Nuclear Electric Insurance Ltd. | $ | 490 | (e) | $ | 7 | |
| (a) | Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended (Price-Anderson). This is subject to retrospective assessment with respect to loss from an incident at any U.S. reactor, payable at $10 million per year. Renewal of Price-Anderson was part of the Energy Policy Act of 2005, which was signed by President Bush in August 2005. Under the 2005 Act, the retrospective assessment with respect to loss from a nuclear incident at any U.S. reactor was increased to $15 million per year. |
| (b) | Limit of liability for each incident under Price-Anderson. |
| (c) | Industry limit for potential liability from workers claiming exposure to the hazards of nuclear radiation. |
| (d) | Includes premature decommissioning costs. |
| (e) | Weekly indemnity of $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus $3.6 million per week for 71.1 weeks thereafter. |
Price-Anderson limits the liability for claims from an incident involving any licensed U.S. nuclear facility. The limit is based on the number of licensed reactors and is adjusted at least every five years to reflect changes in the Consumer Price Index. Utilities owning 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.
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 self-insures the risk. If a serious nuclear incident occurred, it could have a material but indeterminable adverse effect on our 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. In addition, we have entered into various long-term commitments for the purchase of electricity. 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 Ameren Companies’ combined Form 10-K for the fiscal year ended December 31, 2004.
As of June 30, 2005, the commitments for the procurement of coal have increased from amounts previously disclosed as of December 31, 2004. The following table presents the total estimated coal purchase commitments at June 30, 2005:
| | | 2005 | | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | Thereafter(a) |
Ameren(b) | $ | 760 | | $ | 747 | | $ | 699 | | $ | 636 | | $ | 382 | | $ | 114 | |
| UE | | 389 | | | 372 | | | 368 | | | 293 | | | 155 | | | 57 | |
| Genco | | 206 | | | 206 | | | 182 | | | 222 | | | 160 | | | 31 | |
| CILCORP | | 81 | | | 84 | | | 65 | | | 53 | | | 29 | | | 11 | |
| CILCO | | 81 | | | 84 | | | 65 | | | 53 | | | 29 | | | 11 | |
| (a) | Commitments for coal are until 2010. |
| (b) | Includes amounts for Registrant and non-Registrant Ameren subsidiaries and intercompany eliminations. |
As of June 30, 2005, the commitments for the procurement of natural gas have increased from amounts previously disclosed as of December 31, 2004. The following table presents the total estimated natural gas purchase commitments at June 30, 2005:
| | | 2005 | | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | Thereafter(a) |
Ameren(b) | $ | 478 | | $ | 403 | | $ | 218 | | $ | 129 | | $ | 51 | | $ | 22 | |
| UE | | 77 | | | 56 | | | 21 | | | 12 | | | 4 | | | 8 | |
| CIPS | | 81 | | | 79 | | | 53 | | | 40 | | | 25 | | | - | |
| Genco | | 18 | | | 19 | | | 19 | | | 14 | | | 2 | | | 3 | |
| CILCORP | | 156 | | | 136 | | | 64 | | | 50 | | | 16 | | | - | |
| CILCO | | 156 | | | 136 | | | 64 | | | 50 | | | 16 | | | - | |
| IP | | 126 | | | 103 | | | 60 | | | 12 | | | 4 | | | 11 | |
| (a) | Commitments for natural gas are until 2014. |
| (b) | Includes amounts for Registrant and non-Registrant Ameren subsidiaries and intercompany eliminations. |
Environmental Matters
We are subject to various environmental regulations 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, and natural gas storage plants, transmission and distribution facilities, our activities involve compliance with diverse laws and regulations. These address noise, emissions, and impacts to air and water, protected and cultural resources (such as wetlands, endangered species, and archeological/historical resources), and chemical and waste handling. Our activities often require complex and often 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 preparation of 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 their operations, as required. The more significant matters are discussed below.
Clean Air Act
In March 2005, the EPA issued its final regulations with respect to SO2 and NOx emissions (the Clean Air Interstate Rule) and mercury emissions from coal-fired power plants. The new regulations will require significant additional reductions in these emissions from UE, Genco and CILCO power plants in phases, beginning in 2010. The following table presents preliminary estimated capital costs based on current available technology to comply with the Clean Air Interstate Rule and mercury rules:
| | 2005 | 2006 - 2009 | 2010 - 2015 | Total |
| Ameren | $50 | $510 - $ 1,360 | $355 - $1,130 | $1,400 - $1,900 |
| UE | 20 | 160 - 880 | 175 - 880 | 840 - 1,140 |
| Genco | 10 | 250 - 340 | 140 - 200 | 400 - 550 |
| CILCO | 20 | 100 - 140 | 40 - 50 | 160 - 210 |
Each state has 18 months, or until the fall of 2006, to develop state regulation implementing the Clean Air Interstate Rule and mercury rules. While the federal rules mandate a specific emissions cap for SO2, NOx and mercury emissions by state from utility boilers, the states have considerable flexibility in allocating emission allowances to individual utility boilers. In addition, a state may choose to hold back certain emission allowances for growth or other reasons, and may implement a more stringent program than required by the federal rule. The costs reflected in the above table assume each Ameren generating unit will be allocated allowances based on the model “cap and trade” rule guidelines issued by the EPA. Should either Missouri or Illinois decide to develop alternative allowance allocations for utility units, the cost impact could be material. At this time, we are unable to determine the impact such a state decision would have on our results of operations, financial position, or liquidity.
Emission Credits
As of June 30, 2005, UE, Genco, CILCO, and EEI held 1.57 million, 0.52 million, 0.27 million, and 0.29 million tons, respectively, of SO2 emission allowances with vintages from 2005 to 2012. Each company possesses additional allowances for use in periods beyond 2012. As of June 30, 2005, UE, Genco, CILCO and EEI Illinois facilities held 289, 17,446, 4,266 and 5,490 tons, respectively, of NOX emission allowances with vintages from 2004 to 2007. The Illinois Environmental Protection Agency (the Illinois EPA) is still determining some NOx emission allowance allocations for this period and 2008. UE, Genco, CILCO and EEI expect to use a substantial portion of the SO2 and NOx allowances for ongoing operations. Allocations of NOx emission allowances for Missouri facilities are pending the finalization of rules by Missouri regulators. New environmental regulations, including the Clean Air Interstate Rule, the timing of the installation of pollution control equipment, and level of operations will have a significant impact on the amount of allowances actually required for ongoing operations.
New Source Review
The EPA has been conducting an enforcement initiative in an effort to determine whether modifications at a number of coal-fired power plants owned by electric utilities in the U.S. are subject to New Source Review 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 made.
IP and DMG had been the subject of a Notice of Violation from the EPA and a complaint filed in 1999 by the United States in the U.S. District Court for the Southern District of Illinois alleging violations of the Clean Air Act and certain related federal and Illinois regulations in connection with certain equipment repairs, replacements, and maintenance activities at the three Baldwin Power Station generating units, currently owned by DMG and formerly owned by IP.
In May 2005, the court approved a comprehensive settlement among DMG, the EPA, the U.S. and other intervening parties that resolved this litigation. The settlement agreement is set forth in a consent decree and resolves all claims in the litigation as well as similar claims that may have been brought with respect to other generation facilities owned by DMG and formerly owned by IP. This consent decree relieves IP of any civil liability under the Clean Air Act and related federal and Illinois regulations with respect to IP’s former ownership of the Baldwin Power Station and other generation assets now owned by DMG.
In April 2005, Genco 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 its Meredosia, Hutsonville, Coffeen and Newton facilities, EEI’s Joppa facility and AERG’s E.D. Edwards and Duck Creek facilities. All of these facilities are coal-fired power plants. The information request requires Genco to provide responses to specific EPA questions regarding certain projects and maintenance activities in order to determine compliance with certain Illinois air pollution and emissions rules and with the New Source Performance Standard requirements of the Clean Air Act. Genco is complying with this information request, but cannot predict the outcome of this matter at this time.
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 fault, legality of original disposal, or 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 at several contaminated sites. Several of these sites involve facilities that were transferred by CIPS to Genco in May 2000 and were transferred by CILCO to AERG in October 2003. As part of each transfer, CIPS or CILCO has contractually agreed to indemnify Genco or AERG for remediation costs associated with pre-existing environmental contamination at the transferred sites.
As of June 30, 2005, CIPS, CILCO, and IP owned or were otherwise responsible for 14, four, and 25 former MGP sites, respectively, in Illinois. All of these sites are in various stages of investigation, evaluation and remediation. Under its current schedule, Ameren anticipates that remediation at these sites should be completed by 2015. The ICC permits each company to recover remediation and litigation costs associated with their former MGP sites located in Illinois from their Illinois electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred; costs are subject to annual reconciliation review by the ICC. As of June 30, 2005, CIPS, CILCO, and IP had recorded liabilities of $24 million, $4 million, and $64 million, respectively, to represent estimated minimum obligations, which are expected to be recovered through the riders. On May 2, 2005, as a part of its Illinois utility service territory transfer, UE transferred its one Illinois-based former MGP site to CIPS. In connection with the transfer, CIPS succeeded to UE’s ICC-approved environmental adjustment rate rider, which permits CIPS to recover remediation and litigation costs associated with UE’s former MGP site from UE’s transferred Illinois electric and natural gas utility customers. For a discussion of the Illinois service territory transfer, see Note 3 - Rate and Regulatory Matters in this report.
In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one in Iowa. UE does not have in effect in Missouri a rate rider mechanism, which permits remediation costs associated with MGP sites to be recovered from utility customers. UE does not have any retail utility operations in Iowa. Because of the unknown and unique characteristics of each site (such as amount and type of residues present, physical characteristics of the site and the environmental risk), and uncertain regulatory requirements, we are not able to determine the maximum liability for the remediation of these sites. As of June 30, 2005, UE had recorded $16 million to represent its estimated minimum obligation. At this time, we are unable to determine what portion of these costs, if any, will be eligible for recovery from insurance carriers.
In June 2000, the EPA notified UE and numerous other companies that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From approximately 1926 until 1976, UE operated a power generating facility adjacent to Sauget Area 2 and currently owns a parcel of property that is used as a landfill. Under the terms of an Administrative Order and Consent, UE has joined with other potentially responsible parties to evaluate the extent of potential contamination with respect to Sauget Area 2.
In October 2002, UE was included in a Unilateral Administrative Order list of potentially liable parties for groundwater contamination for a portion of the Sauget Area 2 site. The Unilateral Administrative Order encompasses the groundwater contamination releasing to the Mississippi River adjacent to Monsanto Chemical Company’s (now known as Solutia) former chemical waste landfill and the resulting impact area in the Mississippi River. UE was asked to participate in response activities that involve the installation of a barrier wall around a chemical waste site with three recovery wells to divert groundwater flow. The projected cost for this remedy method is $26 million. In November 2002, UE sent a letter to the EPA asserting its defenses to the Unilateral Administrative Order and requested its removal from the list of potentially responsible parties under the Unilateral Administrative Order. Solutia agreed to comply with the Unilateral Administrative Order. However, in December 2003, Solutia filed for bankruptcy protection and is now seeking to discharge its environmental liabilities. In March 2004, Pharmacia Corporation, the former parent company of Solutia, confirmed its intent to comply with the EPA’s Unilateral Administrative Order.
As the status of future remediation at Sauget Area 2 or compliance with the Unilateral Administrative Order is uncertain, we are unable to predict the ultimate impact of the Sauget Area 2 site on our results of operations, financial position, or liquidity. In December 2004, the U.S. Supreme Court, in Cooper Industries, Inc. vs. Aviall Services, Inc., limited the circumstances under which potentially responsible parties could assert cost-recovery claims against other potentially responsible parties. As a result of this ruling, UE may not be able to recover from other potentially responsible parties the costs it incurs in complying with EPA orders. Any liability or responsibility that may be imposed on UE as a result of this Sauget, Illinois environmental matter was not transferred to CIPS as a part of UE’s May 2005 Illinois utility service territory transfer discussed above and in Note 3 - Rate and Regulatory Matters.
In December of 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 $4 million at June 30, 2005, included on their Consolidated Balance Sheets for the estimated cost of the remediation effort to treat and discharge the recycle system water in order to address these groundwater and surface water issues.
In addition, our operations or those of our predecessor companies, involve the use, disposal and, in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine the impact these actions may have on our results of operations, financial position, or liquidity.
Sustainable Energy Plan
In July 2005, the ICC entered a resolution affirming Governor Blagojevich’s Sustainable Energy Plan as well as an ICC Staff Report dated July 7, 2005. Within 30 days of the resolution, CIPS, CILCO and IP are expected to file documentation explaining how they intend to implement the plan. The plan calls for, among other things, a renewable portfolio standard whereby 2% of the bundled retail load should be obtained from renewable energy resources in 2007, 3% in 2008, 4% in 2009, 5% in 2010, 6% in 2011, 7% in 2012 and 8% in 2013; and an energy efficiency portfolio standard whereby there is a 10% reduction in load growth in 2007-2008; 15% in 2009-2011; 20% in 2012-2014; and 25% in 2015-2017.
Asbestos-related Litigation
Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits that have been filed by certain plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The number of total defendants named in each case is significant; as many as 166 parties are named in some pending cases and as few as five in others. However, the average number of parties is 56 in the cases that were pending as of June 30, 2005.
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 most former CILCO plants are now owned by AERG. Most of IP’s plants were transferred to a Dynegy subsidiary prior to Ameren’s acquisition of IP. As a part of the transfer of ownership of the CIPS and CILCO generating plants, CIPS or CILCO has contractually agreed to indemnify Genco or AERG for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages in excess of $50,000, which, if proved, typically would be shared among the named defendants.
From April 1, 2005 through June 30, 2005, four additional asbestos-related lawsuits were filed against UE, CIPS, CILCO and IP, mostly in the Circuit Court of Madison County, Illinois; one lawsuit was dismissed and 13 were settled. The following table presents the status as of June 30, 2005, of the asbestos-related lawsuits that have been filed against the Ameren Companies:
| | | Specifically Named as Defendant |
| Total(a) | | Ameren | | | UE | | | CIPS | | | Genco | | | CILCO | | | IP | |
| Filed | 280 | | 26 | | | 151 | | | 105 | | | 2 | | | 24 | | | 125 | |
| Settled | 71 | | - | | | 44 | | | 29 | | | - | | | 3 | | | 33 | |
| Dismissed | 117 | | 12 | | | 73 | | | 33 | | | 1 | | | 4 | | | 52 | |
| Pending | 92 | | 14 | | | 34 | | | 43 | | | 1 | | | 17 | | | 40 | |
| (a) | Addition of the numbers in the individual columns does not equal the total column because some of the lawsuits name multiple Ameren entities as defendants. |
As of June 30, 2005, four 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.
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.
See Note 3 - Rate and Regulatory Matters - IP and EEI Acquisition under Part II, Item 8 of the Ameren Companies’ combined Form 10-K for the fiscal year ended December 31,
2004, for information on the ICC’s approval of a tariff rider through which asbestos-related litigation claims will be allowed to be recovered from IP’s electric customers, subject to certain terms, commencing in 2007.
Other Matters
Leveraged Leases
Ameren owns interests in assets that have been financed as leveraged leases. One of these leveraged leases is a $10 million investment at June 30, 2005, in an aircraft leased to Delta Air Lines. Delta Air Lines reported significant operating
losses and disclosed in its Form 10-Q filing for the quarter ended March 31, 2005, that it has a transformation plan in place to achieve long-term success by aligning its cost structure with revenues. However, if Delta Air Lines continues to experience significant losses, it would need to seek to restructure under Chapter 11 of the U.S. Bankruptcy Code. Ameren could lose all or a portion of its investment in the Delta Air Lines lease in the event of a bankruptcy or default by Delta Air Lines or any voluntary restructuring of the lease. As of June 30, 2005, Delta Air Lines was current on its payments on this lease.
By order dated April 15, 2004, the SEC determined that certain non-utility interests and investments of CILCORP, including investments in several leveraged lease transactions held by CILCORP’s subsidiary, CIM, or CIM’s subsidiaries, are not retainable by Ameren under PUHCA standards. The non-retainable interests primarily consist of lease interests in commercial real estate properties and equipment. The April 2004 SEC Order requires that Ameren cause CIM or any subsidiary to sell or otherwise dispose of the non-retainable interests. CILCORP is actively pursuing the sale of its interest in these leverage lease transactions.
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 until at least 2012. 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. The Callaway nuclear plant site is assumed to be decommissioned based on immediate dismantlement method and removal from service. Ameren and UE have recorded an asset retirement obligation for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. See the discussion of asset retirement obligations in Note 1 - Summary of Significant Accounting Policies. Decommissioning costs are charged to cost of services used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2004, 2003 and 2002. 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. An updated cost study is expected to be filed in September 2005. 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 in Nuclear Decommissioning Trust Fund in Ameren’s and UE’s Consolidated Balance Sheets. 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 the regulatory asset recorded in connection with the adoption of SFAS No. 143. In connection with UE’s transfer of its Illinois electric and gas utility businesses to CIPS on May 2, 2005, the assets and liabilities related to the Illinois portion of the decommissioning trust fund are being transferred to the Missouri and the FERC jurisdictions. See Note 3 - Rate and Regulatory Matters for further information about this intercompany transfer.
NOTE 11 - STOCKHOLDERS’ EQUITY
Outstanding Shares of Common Stock
The following table reconciles the outstanding shares of Ameren common stock for the three months and six months ended June 30, 2005 and 2004:
| | Three Months | | Six Months | |
| | 2005 | | 2004 | | 2005 | | 2004 | |
| Shares outstanding at beginning of period | | 195.8 | | | 182.5 | | | 195.2 | | | 162.9 | |
| Shares issued | | 8.0 | | | 0.8 | | | 8.6 | | | 20.4 | |
| Shares outstanding at end of period | | 203.8 | | | 183.3 | | | 203.8 | | | 183.3 | |
Paid-In Capital
During the six months ended June 30, 2005, Ameren issued 1.2 million shares of common stock valued at $57 million under DRPlus and Ameren’s 401(k) plans and 7.4 million shares of common stock in exchange for proceeds of $345 million to holders of the adjustable conversion-rate equity security units offset by $5 million related to open market purchases for employee stock options and restricted stock awards. See Note 5 - Long-term Debt and Equity Financings for further information.
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 shareholders. A reconciliation of net income to comprehensive income for the three months and six months ended June 30, 2005 and 2004 is shown below for the Ameren Companies:
| | Three Months | Six Months |
| | | 2005 | | | 2004 | | | 2005 | | | 2004 | |
Ameren:(a) | | | | | | | | | | | | |
| Net income | $ | 185 | | $ | 118 | | $ | 306 | | $ | 215 | |
Unrealized gain on derivative hedging instruments, net of taxes (benefit) of $4, $3, $10, and $3, respectively | | 1 | | | 6 | | | 18 | | | 6 | |
Reclassification adjustments for (gains) included in net income, net of taxes (benefit) of $1, $1, $1, and $(1), respectively | | (2 | ) | | (3 | ) | | (2 | ) | | (3 | ) |
| Total comprehensive income, net of taxes | $ | 184 | | $ | 121 | | $ | 322 | | $ | 218 | |
UE: | | | | | | | | | | | | |
Net income | $ | 132 | | $ | 109 | | $ | 189 | | $ | 167 | |
Unrealized gain (loss) on derivative hedging instruments, net of taxes of $-, $-, $2, and $1, respectively | | (1 | ) | | 1 | | | 3 | | | 3 | |
Total comprehensive income, net of taxes$ | $ | 131 | | $ | 110 | | $ | 192 | | $ | 170 | |
CIPS: | | | | | | | | | | | | |
Net income | $ | 7 | | $ | 8 | | $ | 15 | | $ | 18 | |
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(1), $1, $3, and $2, respectively | | (2 | ) | | 1 | | | 4 | | | 4 | |
Reclassification adjustments for (gains) included in net income, net of taxes (benefit) of $(1), $-, $- and $-, respectively | | (1 | ) | | - | | | (1 | ) | | (1 | ) |
Total comprehensive income, net of taxes | $ | 4 | | $ | 9 | | $ | 18 | | $ | 21 | |
Genco: | | | | | | | | | | | | |
Net income | $ | 31 | | $ | 17 | | $ | 62 | | $ | 46 | |
Unrealized (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $-, $-, and $(1), respectively | | - | | | - | | | (1 | ) | | (1 | ) |
Reclassification adjustments for (gains) included in net income, net of taxes of $-, $-, $-, and $-, respectively | | - | | | (1 | ) | | - | | | (1 | ) |
Total comprehensive income, net of taxes | $ | 31 | | $ | 16 | | $ | 61 | | $ | 44 | |
CILCORP: | | | | | | | | | | | | |
Net income (loss) | $ | 2 | | $ | (4 | ) | $ | 11 | | $ | - | |
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(1), $1, $7, and $2, respectively | | (1 | ) | | 3 | | | 12 | | | 6 | |
Reclassification adjustments for (gains) losses included in net income, net of taxes (benefit) of $-, $(1), $-, and $(1), respectively | | (1 | ) | | (2 | ) | | 1 | | | (2 | ) |
Total comprehensive income (loss), net of taxes | $ | - | | $ | (3 | ) | $ | 24 | | $ | 4 | |
CILCO: | | | | | | | | | | | | |
Net income | $ | 10 | | $ | 3 | | $ | 26 | | $ | 9 | |
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(1), $1, $7, and $2, respectively | | (1 | ) | | 3 | | | 11 | | | 6 | |
Reclassification adjustments for (gains) included in net income, net of taxes (benefit) of $-, $(1), $-, and $(1), respectively | | (1 | ) | | (2 | ) | | - | | | (2 | ) |
Total comprehensive income, net of taxes | $ | 8 | | $ | 4 | | $ | 37 | | $ | 13 | |
IP:(b) | | | | | | | | | | | | |
Net income | $ | 15 | | $ | 24 | | $ | 37 | | $ | 61 | |
Minimum pension liability adjustment, net of taxes of $-, $-, $- and $-, respectively | | - | | | - | | | - | | | 1 | |
Total comprehensive income, net of taxes | $ | 15 | | $ | 24 | | $ | 37 | | $ | 62 | |
| (a) | Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP. |
| (b) | Includes predecessor information for 2004. |
NOTE 12 - RETIREMENT BENEFITS
Ameren’s pension plans are funded in compliance with income tax regulations and federal funding requirements. Based on our assumptions at December 31, 2004, in order to maintain minimum funding levels for Ameren’s pension plans, we expect future required contributions to aggregate $400 million for the period of 2005 to 2009, with no minimum
contribution required until 2008 assuming continuation of the current federal interest rate relief beyond 2005. These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in government regulations.
Ameren made a contribution to its post-retirement plan of $35 million in the second quarter of 2005 as compared to $32 million in the second quarter of the prior year.
The following table presents Ameren’s net periodic benefit costs (and the components of those costs) for pension and other postretirement benefits for the three months and six months ended June 30, 2005 and 2004:
| | Pension Benefits(a) |
| | Three Months | Six Months |
| | | 2005 | | | 2004 | | | 2005 | | | 2004 |
Service cost | $ | 14 | | $ | 10 | | $ | 29 | | $ | 21 | |
Interest cost | | 41 | | | 32 | | | 83 | | | 65 | |
Expected return on plan assets | | (45 | ) | | (30 | ) | | (91 | ) | | (60 | ) |
| Amortization cost: | | | | | | | | | | | | |
Prior service cost | | 3 | | | 3 | | | 5 | | | 5 | |
Losses | | 9 | | | 5 | | | 19 | | | 12 | |
Net periodic benefit cost | $ | 22 | | $ | 20 | | $ | 45 | | $ | 43 | |
| | Postretirement Benefits(a) | |
| | Three Months | | Six Months | |
| | 2005 | | 2004 | | 2005 | | 2004 | |
Service cost | $ | 5 | | $ | 3 | | $ | 11 | | $ | 7 | |
Interest cost | | 17 | | | 10 | | | 36 | | | 27 | |
Expected return on plan assets | | (11 | ) | | (7 | ) | | (23 | ) | | (16 | ) |
| Amortization cost: | | | | | | | | | | | | |
| Transition obligation | | 1 | | | - | | | 1 | | | - | |
Prior service cost | | (1 | ) | | (1 | ) | | (2 | ) | | (2 | ) |
Losses | | 9 | | | 4 | | | 19 | | | 14 | |
Net periodic benefit cost | $ | 20 | | $ | 9 | | $ | 42 | | $ | 30 | |
| (a) | Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP. |
UE, CIPS, Genco, CILCORP, CILCO and IP are participants in Ameren’s plans and are responsible for their proportional share of the pension and other postretirement costs. The following table presents the pension and other postretirement costs incurred for the three months and six months ended June 30, 2005 and 2004:
| | Pension Benefits | |
| | Three Months | | Six Months | |
| | 2005 | | 2004 | | 2005 | | 2004 | |
Ameren(a) | $ | 22 | | $ | 20 | | $ | 45 | | $ | 43 | |
| UE | | 13 | | | 12 | | | 26 | | | 26 | |
| CIPS | | 3 | | | 3 | | | 6 | | | 6 | |
| Genco | | 2 | | | 2 | | | 4 | | | 4 | |
| CILCORP | | 3 | | | 3 | | | 6 | | | 7 | |
| CILCO | | 5 | | | 4 | | | 9 | | | 10 | |
IP(b) | | 1 | | | - | | | 3 | | | - | |
| | Postretirement Benefits | |
| | Three Months | | Six Months | |
| | 2005 | | 2004 | | 2005 | | 2004 | |
Ameren(a) | $ | 20 | | $ | 9 | | $ | 42 | | $ | 30 | |
| UE | | 11 | | | 4 | | | 22 | | | 17 | |
| CIPS | | 3 | | | 2 | | | 6 | | | 5 | |
| Genco | | 1 | | | - | | | 2 | | | 1 | |
| CILCORP | | 2 | | | 3 | | | 6 | | | 7 | |
CILCO | | 3 | | | 5 | | | 9 | | | 11 | |
IP(b) | | 3 | | | - | | | 6 | | | - | |
| (a) | Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP. |
| (b) | Includes predecessor information for 2004. |
NOTE 13 - SEGMENT INFORMATION
As discussed in the Ameren Companies combined Form 10-K for the fiscal year ended December 31, 2004, Ameren’s two reportable segments are: (1) Utility Operations, which generates electricity and transmits and distributes natural gas and electricity and (2) Other, which is comprised of the parent holding company, Ameren Corporation.
Ameren’s reportable segment Utility Operations includes the operations of UE, CIPS, Genco, CILCORP and CILCO. The operations of IP are included in Ameren’s Utility Operations segment from September 30, 2004.
The accounting policies for segment data are the same as those described in Note 1 - Summary of Significant Accounting Policies. Segment data include intersegment revenues, as well as a charge for allocating costs of administrative support services to each of the operating companies, which, in each case, is eliminated upon consolidation. Ameren Services allocates administrative support services based on various factors, such as headcount, number of customers, and total assets. The following table presents information about the reported revenues and net income of Ameren for the three months and six months ended June 30, 2005 and 2004:
| | Utility Operations | | Other | | Reconciling Items(a) | | Total | |
Three Months 2005: | | | | | | | | | | | | |
| Operating revenues | $ | 1,956 | | $ | - | | $ | (366 | ) | $ | 1,590 | |
| Net income | | 186 | | | (1 | ) | | - | | | 185 | |
Three Months 2004:(b) | | | | | | | | | | | | |
| Operating revenues | $ | 1,432 | | $ | - | | $ | (283 | ) | $ | 1,149 | |
| Net income | | 115 | | | 3 | | | - | | | 118 | |
Six Months 2005: | | | | | | | | | | | | |
| Operating revenues | $ | 3,900 | | $ | - | | $ | (684 | ) | $ | 3,216 | |
| Net income | | 311 | | | (5 | ) | | - | | | 306 | |
Six Months 2004:(b) | | | | | | | | | | | | |
| Operating revenues | $ | 2,948 | | $ | - | | $ | (580 | ) | $ | 2,368 | |
| Net income | | 212 | | | 3 | | | - | | | 215 | |
| (a) | Elimination of intercompany revenues. |
| (b) | Excludes 2004 amounts for IP. |
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
OVERVIEW
Ameren Executive Summary
Ameren’s earnings per share in the second quarter and first six months of 2005 benefited from stronger interchange power sales margins, earnings from IP, hotter-than-normal summer weather, and the lack of a refueling and maintenance outage at UE’s Callaway nuclear plant in the current year.
Increased power plant availability and the MISO Day Two Market provided the opportunity for increased interchange sales versus the year-ago period while power prices were also higher.
This year, CIPS, CILCO and IP have made filings with the ICC outling a proposed method for procuring power in 2007 and beyond. Hearings on this proposal are scheduled for September 2005. By the end of 2005, CIPS, CILCO and IP are expected to make filings with the ICC that will serve as a basis for adjusting electric distribution rates. By January 1, 2006, UE will provide an updated cost of service study to the MoPSC staff and others. These are milestone events for Ameren.
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company registered with the SEC under the PUHCA. Ameren’s primary asset is the common stock of its subsidiaries. Ameren’s 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 as discussed below. Dividends on Ameren’s common stock are dependent on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part I, Item 1, of this report for a detailed description of Ameren’s principal subsidiaries.
| · | UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri and prior to May 2, 2005, in Illinois. |
| · | 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 is a subsidiary of CILCORP (a holding company) and operates a rate-regulated electric transmission and distribution business, a primarily non-rate-regulated electric generation business through its subsidiary, AERG, and a rate-regulated natural gas transmission and distribution business in Illinois. |
| · | IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. See Note 2 - Acquisitions to our financial statements under Part I, Item 1, of this report for further information. |
The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. As the acquisition of IP occurred on September 30, 2004, Ameren’s Consolidated Statements of Income and Cash Flows for the three months and six months ended June 30, 2004, do not reflect IP’s results of operations or financial position. See Note 2 - Acquisitions for further information on the accounting for the IP acquisition. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
In addition to presenting results of operations and earnings amounts in total, certain information in this report is expressed in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information is useful because it enables 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 weighted-average diluted common shares outstanding during the applicable period.
IP Acquisition
On September 30, 2004, Ameren completed the acquisition of all the common stock and 662,924 shares of preferred stock of IP and an additional 20% ownership interest in EEI from subsidiaries of Dynegy. Ameren acquired IP to complement its existing Illinois gas and electric operations. The purchase included IP’s rate-regulated electric and natural gas transmission and distribution business serving 600,000 electric and 415,000 gas customers in areas contiguous to our existing Illinois utility service territories. With the acquisition, IP became an Ameren subsidiary operating as AmerenIP.
The total transaction value was $2.3 billion, including the assumption of $1.8 billion of IP debt and preferred stock and consideration, including transaction costs, of $440 million in cash, net of $51 million cash acquired and a working capital adjustment of $5 million received from Dynegy in February 2005 pursuant to the terms of the stock purchase agreement. Ameren placed $100 million of the cash portion of the purchase price in a six-year escrow account pending resolution of certain contingent environmental obligations of IP and other Dynegy affiliates for which Ameren was provided indemnification by Dynegy. On July 27, 2005, the conditions for release of the escrow account were satisfied and Dynegy was remitted the $100 million. In addition, this transaction included a fixed-price capacity power supply agreement for IP’s annual purchase in 2005 and 2006 of 2,800 megawatts of electricity from DYPM. This agreement is expected to supply about 70% of IP’s electric customer requirements during those two years. The remaining 30% of IP’s power needs in 2005 and 2006 will be supplied by other companies through contracts and open market purchases. In the event that suppliers are unable to supply the electricity required by existing agreements, IP would be forced to find alternative suppliers to meet its load requirements, thus exposing itself to market price risk, which could have a material impact on Ameren’s and IP’s results of operations, financial position, or liquidity.
Ameren funded this acquisition with the issuance of new Ameren common stock. Ameren issued an aggregate of 30 million common shares in February 2004 and July 2004, which generated net proceeds of $1.3 billion. Proceeds from these issuances were used to finance the cash portion of the purchase price and to reduce IP debt assumed as part of this transaction and to pay related premiums.
Ameren expects the acquisition of IP to be accretive to earnings in the first two years of ownership. That belief is based on a variety of assumptions related to power prices, interest rates, and synergies, among other things.
For income tax purposes, Ameren and Dynegy have elected to treat Ameren’s acquisition of IP stock as an asset acquisition under Section 338(h)(10) of the Internal Revenue Code of 1986, as amended.
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 caused by winter heating and summer cooling demand. With approximately 85% of Ameren’s revenues directly subject to regulation by various state and federal agencies, decisions by regulators can have a material impact on the prices we charge for our services. Our non-rate-regulated sales are subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, and oil in our operations. The prices for these commodities can fluctuate significantly due to the world economic and political environment, weather, supply and demand levels and many other factors. We do not currently have fuel or purchased power cost recovery mechanisms in Missouri or Illinois for our electric utility businesses, but we do have gas cost recovery mechanisms (PGAs) in each state for our gas delivery businesses. The electric and gas rates for UE in Missouri are set through June 2006, and electric rates are set for CIPS, CILCO and IP in Illinois through the end of 2006, so that cost decreases or increases will not be immediately reflected in rates. Fluctuations in interest rates affect our cost of borrowing and pension and postretirement benefits. We employ various risk management strategies in order to try to reduce our exposure to commodity risks and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems and the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control in order to optimize our results of operations, financial position, and liquidity.
Ameren’s net income increased $67 million to $185 million, or 93 cents per share, in the second quarter of 2005 from $118 million, or 65 cents per share, in the second quarter of 2004. Ameren’s net income increased $91 million to $306 million, or $1.55 per share, for the six months ended June 30, 2005, compared to year-ago earnings of $215 million, or $1.20
per share in the first six months of 2004. The change in net income for the three months and six months ended June 30, 2005 was primarily due to the inclusion of IP results in the current year, increased margins on interchange power sales, hotter-than-normal weather conditions in the second quarter of 2005, and the lack of a refueling and maintenance outage at UE’s Callaway nuclear plant in the second quarter of 2005. The Callaway nuclear plant had a 64-day maintenance and refueling outage in the second quarter of 2004. The lack of a refueling outage in the current year also contributed to improved power plant availability, which provided the opportunity for increased interchange sales. Partially offsetting these increases to net income were decreased emission allowance sales and higher fuel prices, labor and employee benefit cost and depreciation expenses in the current year periods. In addition, second quarter 2004 net income benefited from a FERC-ordered refund of $18 million in exit fees, which had been previously paid by UE and CIPS to the MISO, upon their re-entry into the MISO.
As a holding company, Ameren’s net income 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 Ameren’s consolidated net income for the three months and six months ended June 30, 2005 and 2004:
| | Three Months | | Six Months | |
| | 2005 | | 2004 | | 2005 | | 2004 | |
| Net income: | | | | | | | | | | | | |
UE(a) | $ | 130 | | $ | 107 | | $ | 186 | | $ | 164 | |
| CIPS | | 7 | | | 8 | | | 14 | | | 17 | |
Genco(a) | | 31 | | | 17 | | | 62 | | | 46 | |
CILCORP(a) | | 2 | | | (4 | ) | | 11 | | | - | |
IP(b) | | 15 | | | - | | | 36 | | | - | |
Other(c) | | - | | | (10 | ) | | (3 | ) | | (12 | ) |
| Ameren net income | $ | 185 | | $ | 118 | | $ | 306 | | $ | 215 | |
| (a) | Includes earnings from unregulated interchange power sales that provided $30 million and $52 million of UE’s net income in the three months and six months ended June 30, 2005, respectively, (2004 - second quarter - $15 million; year-to-date - $32 million), $18 million and $30 million of Genco’s net income in the three months and six months ended June 30, 2005, respectively, (2004 - second quarter - $7 million; year-to-date - $17 million) and $4 million and $9 million of CILCORP’s net income in the three months and six months ended June 30, 2005, respectively. |
| (b) | Ameren acquired IP on September 30, 2004. |
| (c) | Includes corporate general and administrative expenses, transition costs associated with the IP acquisition and other non-rate-regulated operations. |
Acquisition Accounting
The amortization of noncash purchase accounting fair value adjustments at IP and Resources Company increased Ameren’s and IP’s net income by $13 million and $9 million, respectively, for the three months, and $26 million and $19 million, respectively, for the six months ended June 30, 2005, as compared with the same prior-year periods. The amortization of the fair value adjustments at IP that increased net income were related to pension and postretirement liabilities, long-term debt, and a power supply contract with Dynegy to supply IP 2,800 megawatts for 2005 and 2006. Partially offsetting these items at IP was the amortization of the fair value adjustment related to a power supply contract with EEI that expires in 2005. The following table presents the favorable (unfavorable) impact on Ameren’s and IP’s net income related to the amortization of purchase accounting fair value adjustments associated with the IP acquisition during the three months and six months ended June 30, 2005:
| | Three Months | | Six Months | |
| | Ameren | | IP | | Ameren | | IP | |
| Statement of Income line item: | | | | | | | | | | | | |
Other operations and maintenance(a) | $ | 7 | | $ | 7 | | $ | 13 | | $ | 13 | |
Interest(b) | | 4 | | | 4 | | | 10 | | | 10 | |
Purchased power(c) | | 10 | | | 4 | | | 20 | | | 8 | |
Income taxes(d) | | (8 | ) | | (6 | ) | | (17 | ) | | (12 | ) |
| Impact on net income | $ | 13 | | $ | 9 | | $ | 26 | | $ | 19 | |
| (a) | Related to the adjustment to fair value of the pension plan and postretirement plans. |
| (b) | Related to the adjustment to fair value of all the IP debt assumed at acquisition on September 30, 2004, and the unamortized gain or loss on reacquired debt. The net write-up to fair value of all the IP debt assumed, excluding early redemption premiums, is being amortized over the anticipated remaining life of the debt. |
| (c) | Related to the amortization of fair value adjustments to power supply contracts. |
| (d) | Tax effect of the above amortization adjustments. |
The amortization of fair value adjustments at EEI as a result of the additional 20% interest acquired by Ameren on September 30, 2004, were related to plant in service, emission credits and a power supply agreement with IP that expires in 2005. The following table presents the favorable (unfavorable) impact on Ameren’s net income related to the amortization of purchase accounting fair value adjustments associated with the EEI acquisition during the three months and six months ended June 30, 2005:
| | Three Months | | Six Months | |
| Statement of Income line item: | | | | | | |
Interchange revenues(a) | $ | 1 | | $ | 2 | |
Fuel and purchased power(b) | | (1 | ) | | (2 | ) |
Depreciation and amortization(c) | | - | | | (1 | ) |
Income taxes(d) | | - | | | - | |
| Impact on net income | $ | - | | $ | (1 | ) |
| (a) | Related to the amortization of a power supply contract. |
| (b) | Related to the amortization of emission credits. |
| (c) | Includes the amortization of the fair value adjustment related to plant assets. |
| (d) | Tax effect of the above amortization adjustments. |
Electric Operations
The following table presents the favorable (unfavorable) variations in electric margins, defined as electric revenues less fuel and purchased power costs, for the three months and six months ended June 30, 2005, from the comparable periods in 2004. We consider electric and interchange margins useful measures to analyze the change in profitability of our electric operations between periods. We have included the analysis below as a complement to our financial information provided in accordance with GAAP. However, electric and interchange 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 are providing elsewhere in this report.
The variation for Ameren shows the contribution from IP for the three months and six months ended June 30, 2005, as a separate line item, which facilitates comparison of other margin components. IP’s electric margins in 2005 include purchase accounting adjustments and are compared with the same periods in 2004 when Ameren did not own IP and it did not contribute to Ameren’s electric margins.
| | Ameren(a) | | UE | | CIPS | | Genco | | CILCORP | | CILCO | | IP(b) | |
Three Months | | | | | | | | | | | | | | |
| Electric revenue change: | | | | | | | | | | | | | | | | | | | | | |
| IP | $ | 268 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| Effect of weather (estimate) | | 13 | | | 7 | | | 3 | | | - | | | 3 | | | 3 | | | 9 | |
| Growth and other (estimate) | | 41 | | | 8 | | | 31 | | | 27 | | | 6 | | | 5 | | | 1 | |
| Emission credits | | (5 | ) | | (5 | ) | | - | | | - | | | - | | | - | | | - | |
Interchange revenues | | 67 | | | 58 | | | (2 | ) | | 31 | | | 2 | | | 2 | | | - | |
| Total | $ | 384 | | $ | 68 | | $ | 32 | | $ | 58 | | $ | 11 | | $ | 10 | | $ | 10 | |
| Fuel and purchased power change: | | | | | | | | | | | | | | | | | | | | | |
| IP | $ | (165 | ) | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| Fuel: | | | | | | | | | | | | | | | | | | | | | |
Generation and other | | (26 | ) | | (19 | ) | | - | | | (4 | ) | | (2 | ) | | (2 | ) | | - | |
Price | | (13 | ) | | (4 | ) | | - | | | (9 | ) | | - | | | - | | | - | |
Purchased power | | (8 | ) | | (17 | ) | | (26 | ) | | (34 | ) | | (4 | ) | | (4 | ) | | (11 | ) |
| Total | $ | (212 | ) | $ | (40 | ) | $ | (26 | ) | $ | (47 | ) | $ | (6 | ) | $ | (6 | ) | $ | (11 | ) |
| Net change in electric margins | $ | 172 | | $ | 28 | | $ | 6 | | $ | 11 | | $ | 5 | | $ | 4 | | $ | (1 | ) |
Six Months | | | | | | | | | | | | | | | | | | | | | |
| Electric revenue change: | | | | | | | | | | | | | | | | | | | | | |
| IP | $ | 503 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| Effect of weather (estimate) | | 8 | | | 5 | | | 2 | | | - | | | 1 | | | 1 | | | 7 | |
| Growth and other (estimate) | | 33 | | | 4 | | | 33 | | | 33 | | | (1 | ) | | (2 | ) | | (9 | ) |
| Emission credits | | (20 | ) | | (20 | ) | | - | | | - | | | - | | | - | | | - | |
| Rate reductions | | (7 | ) | | (7 | ) | | - | | | - | | | - | | | - | | | - | |
| Interchange revenues | | 80 | | | 71 | | | (2 | ) | | 34 | | | 6 | | | 6 | | | - | |
| Total | $ | 597 | | $ | 53 | | $ | 33 | | $ | 67 | | $ | 6 | | $ | 5 | | $ | (2 | ) |
| Fuel and purchased power change: | | | | | | | | | | | | | | | | | | | | | |
| IP | $ | (322 | ) | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| Fuel: | | | | | | | | | | | | | | | | | | | | | |
Generation and other | | (28 | ) | | (28 | ) | | - | | | 10 | | | (6 | ) | | (3 | ) | | - | |
Price | | (23 | ) | | (8 | ) | | - | | | (19 | ) | | 4 | | | 3 | | | - | |
Purchased power | | 19 | | | (2 | ) | | (32 | ) | | (43 | ) | | 8 | | | 8 | | | (17 | ) |
| Total | $ | (354 | ) | $ | (38 | ) | $ | (32 | ) | $ | (52 | ) | $ | 6 | | $ | 8 | | $ | (17 | ) |
| Net change in electric margins | $ | 243 | | $ | 15 | | $ | 1 | | $ | 15 | | $ | 12 | | $ | 13 | | $ | (19 | ) |
| (a) | Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations. |
| (b) | Compared to predecessor information for the three months and six months ended June 30, 2004. |
Ameren
Ameren’s electric margin increased $172 million for the three months and $243 million for the six months ended June 30, 2005, compared with the same periods in 2004. The acquisition of IP added electric margins of $103 million and $181 million in the three months and six months, respectively. Electric margin also increased due to increased interchange margins as discussed below. Favorable weather conditions contributed to increased margins in the second quarter of the current year, offsetting the effect of mild weather in our service territory in the first quarter of 2005. Partially offsetting these increases to margin were reduced industrial sales, higher fuel prices, and lower sales of emission allowances in the current year. Revenues from emission credit sales at UE decreased $5 million and $20 million for the second quarter and first six months of 2005, respectively, as compared with the same periods in 2004, as UE continues to evaluate options for complying with the Clean Air Interstate Rule, which includes the possibility of using emission credits for compliance purposes. Electric rate reductions resulting from the 2002 UE electric rate case settlement in Missouri negatively affected
electric revenues by $7 million during the first quarter of 2005. These were the final rate reductions under the rate case settlement.
Margins on interchange sales increased $42 million for the three months and $62 million for the six months ended June 30, 2005, compared with the same periods in 2004. Interchange margins increased principally because of increased availability of low-cost generation resulting from improved power plant availability, including the lack of a Callaway nuclear plant refueling outage in the current year period. Ameren’s baseload electric generating plants’ average capacity factors were approximately 78% and 77% for the second quarter and first six months of 2005 compared with 72% and 73% for the same periods in 2004. Equivalent availability factors were 86% and 85% for the second quarter and first six months of 2005 compared with 80% and 81% for the prior-year periods. High natural gas, emission allowance and coal prices in 2005 contributed to higher power prices. Average realized power prices on interchange sales increased to approximately $38 per megawatthour in both the second quarter and first six months of 2005, from approximately $30 per megawatthour in the comparable periods of 2004.
We experienced mild winter weather conditions during the first quarter of 2005 compared with the same period in 2004. Heating degree-days during that period in our service territory were down 4% from the prior year and down 8% from normal conditions. Cooling degree-days increased 6% in the second quarter of 2005 compared to the prior year period and increased over 20% from normal conditions, more than offsetting the effect of the mild weather in the first quarter of 2005. Excluding IP sales, weather-sensitive residential and commercial sales were up 6% and 2%, for the three months and six months ended June 30, 2005, respectively, compared with the same periods in the prior year.
Industrial sales, excluding IP sales in the current year, declined 5% in the second quarter and first six months of 2005, primarily as a result of the expiration and non-renewal of low-margin power sales contracts outside of our core service territory along with the decreased resale of power to the DOE by EEI. Partially offsetting these decreases were sales to Noranda - a significant new customer at UE as discussed below. Excluding these items, industrial sales were comparable to the same period in the prior year.
Ameren’s fuel and purchased power costs, excluding the IP results, increased $47 million in the three months and $32 million in the six months ended June 30, 2005, compared with the same periods of 2004, as increased purchased power prices, higher fuel costs, MISO administrative fees and increased generation at UE in the current year offset higher purchased power volume in the prior year caused by the Callaway plant refueling and maintenance outage.
UE
UE’s electric margin increased $28 million over the second quarter of 2004 and $15 million for the six months ended June 30, 2005, compared with the same period in 2004. Electric margin for the periods benefited from increased interchange sales margins. Margins on interchange sales with non-affiliates increased $25 million in the second quarter and $33 million in the first six months of 2005, compared with the same periods of 2004, primarily because of increased volume. Margins on sales to affiliates also increased over the same periods in 2004 because of increased sales to Genco under the joint dispatch agreement resulting from a major power plant maintenance outage at Genco in 2005. Favorable weather conditions in the second quarter more than offset mild weather in the first quarter resulting in an increase in weather-sensitive residential and commercial sales of 3% in the second quarter of 2005. Year-to date sales were comparable in the first six months of 2005 compared to the same period in 2004. Rate reductions in the first quarter of the current year negatively impacted margin for the six-month period. In addition, emission credit sales decreased $5 million and $20 million for the second quarter and first six months of 2005, respectively, as compared with the same periods in 2004.
On May 2, 2005, following the receipt of all required regulatory approvals, UE completed the transfer of its Illinois-based electric and natural gas utility businesses, including its Illinois-based distribution assets, and certain of its transmission assets, to CIPS. The transfer resulted in an estimated decrease in electric margin of $23 million in the second quarter of 2005.
UE entered into a 15 year agreement with Noranda to supply approximately 470 megawatts (peak load) electric service (or approximately 5% of UE’s generating capability, including currently committed purchases) to Noranda’s primary aluminum smelter in southeast Missouri. The additional sales to Noranda increased electric margin by $10 million in the second quarter of 2005. Overall, industrial sales were comparable in the second quarter of 2005 compared to the same period in 2004 as the effect of UE’s Illinois service territory transfer to CIPS was offset by the increased sales to Noranda and by economic growth.
Fuel and purchased power increased in the second quarter and first six months of 2005 compared to the same periods in 2004 as increased purchased power prices, MISO administrative fees and increased generation in the current year offset higher purchased power volume of $24 million in the prior year caused by the Callaway refueling and maintenance outage.
CIPS
CIPS’ electric margin increased $6 million in the three months, but was comparable for the six months, ended June 30, 2005 as compared with the same periods in 2004. The increase in the second quarter was primarily due to favorable weather conditions and increased industrial sales as a result of the Illinois service territory transfer from UE, partially offset by increased purchased power costs related to the transfer. This increase to margin offset the effect of unfavorable weather conditions in the first quarter of 2005.
Genco
Genco’s electric margin increased $11 million in the three months and $15 million in the six months ended June 30, 2005, as compared with the same periods of 2004. The increase in electric margin was primarily attributable to an increase in wholesale margins on sales to new customers and increased interchange margins. Interchange margins increased $16 million in the three months and $20 million in the six months ended June 30, 2005, compared with the same periods of 2004, primarily because of increased volume. Partially offsetting these increases was a loss of $6 million due to the settlement of SO2 emission allowance options in the first quarter of 2005. Increased purchased power, principally from UE under the joint dispatch agreement, was the result of a major power plant maintenance outage, which occurred primarily during the first quarter of 2005, in addition to higher purchased power prices from outside sources.
CILCORP and CILCO
Electric margin at CILCORP and CILCO increased $5 million and $4 million, respectively, in the three months and $12 million and $13 million, respectively, in the six months ended June 30, 2005, compared with the same periods of 2004. Increases in electric margin were due to increased interchange margins and the use of lower cost coal at one of AERG’s power plants along with the effect of favorable weather conditions in the second quarter of the current year, partially offset by transfers of non-rate-regulated customers to Marketing Company. Purchased power increased in the second quarter of 2005 over the year-ago period principally due to reduced plant availability at AERG and hotter weather.
IP
IP’s electric margin was comparable in the three months ended June 30, 2005 to the same period in the prior year, but decreased $19 million in the six-month period of 2005 as compared to the same period in 2004 primarily because of reduced industrial revenues due to customers choosing alternative suppliers. In addition, purchased power costs increased due to higher net power prices. While power costs decreased under IP’s power supply agreement with DYPM, costs on remaining power purchase contracts were higher than in the same periods of the prior year. Favorable weather conditions partially offset the above reductions to margin for the three months and six months in 2005.
Gas Operations
The following table presents the favorable (unfavorable) variations in gas margins, defined as gas revenues less gas purchased for resale, for the three months and six months ended June 30, 2005, from the comparable periods in 2004. We consider gas margin to be a useful measure to analyze the change in profitability of our gas utility operations between periods. We have included the table below as a complement to our financial information provided in accordance with GAAP. However, gas margin 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 are providing elsewhere in this report.
| | Three Months | | Six Months | |
Ameren(a) | $ | 24 | | $ | 78 | |
| UE | | 2 | | | 4 | |
| CIPS | | (c | ) | | (4 | ) |
| CILCORP | | (2 | ) | | (2 | ) |
| CILCO | | (2 | ) | | (1 | ) |
IP(b) | | 2 | | | (3 | ) |
| (a) | Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations. |
| (b) | Compared to predecessor information for the three months and six months ended June 30, 2004. |
| (c) | Less than $1 million. |
Ameren’s gas margin increased $24 million for the quarter and $78 million for the six months ended June 30, 2005, as compared to the same prior year periods, due to the inclusion of IP results in the current year. Excluding the IP results, gas margin decreased $5 million in the second quarter of 2005 compared to the year ago period because of hotter weather conditions. Excluding IP, Ameren’s gas margin was comparable for the first six months of 2005 to the first six months of 2004. For the current six-month period, rate increases at UE along with increased transportation revenues offset the negative effect of mild winter weather. Gas sales in the first six months of 2005 increased almost 39%, due to the IP acquisition, while gas sales in Ameren’s preacquisition service territory were down 20% in the same period due to the mild weather primarily in the first quarter of the current year. UE’s gas margin increased for the six months ended June 30, 2005, as compared with the same period in the prior year, primarily due to the effect of rate increases of $3 million in the first quarter of 2005. CILCORP’s and CILCO’s gas margins decreased for the three months and six months of 2005 primarily due to unfavorable weather conditions. CIPS’ gas margin decreased for the first six months of the current year due to the mild weather, but was comparable for the second quarter to the same period in the prior year. IP’s gas margin
decreased for the first six months of the current year due to unfavorable weather in the first quarter of 2005, partially offset by a rate increase effective in May 2005.
Operating Expenses and Other Statement of Income Items
Other Operations and Maintenance
Ameren’s other operations and maintenance expenses increased $30 million for the three months and $69 million for the six months ended June 30, 2005, compared with the same periods in 2004. The IP results in the current year accounted for other operations and maintenance expenses of $60 million in the second quarter and $102 million in the first six months. Excluding the IP results in the current year, other operations and maintenance expenses decreased in both periods primarily due to decreased power plant maintenance and labor costs of $39 million, which was primarily a result of the refueling and maintenance outage at UE’s Callaway nuclear plant during the second quarter of 2004. However, Ameren, UE and CIPS, received a refund of previously paid exit fees of $18 million upon their re-entry into the MISO during the second quarter of 2004. This refund did not recur in 2005 and therefore other operations and maintenance expenses increased relative to 2004 for this item.
Other operations and maintenance expenses at UE decreased $11 million in the three months and $20 million in the six months ended June 30, 2005, compared with the same periods of 2004, primarily as a result of decreased power plant maintenance and labor costs at Callaway as a result of the refueling and maintenance outage in the second quarter of 2004 and an unscheduled outage at Callaway in the first quarter of the prior year. The timing of planned outages at other UE plants resulted in increased maintenance expenses in the second quarter of 2005 compared to the same period in the prior year. Additionally, other operations and maintenance expenses increased for the second quarter and first six months of 2005, compared to the same period in 2004, because of the receipt of the MISO refund during the second quarter of the prior year of which UE’s portion was $12 million.
Other operations and maintenance expenses at CIPS were comparable in the three months ended June 30, 2005, but decreased $5 million for the first six months of 2005, as compared with the same periods in 2004. CIPS’ portion of the MISO refund in the prior year of $5 million was offset by decreases in various other operations and maintenance expenses in the current year.
Genco’s other operations and maintenance expenses decreased $5 million in the three months ended June 30, 2005, as compared with the same period in 2004, because of decreases in various other operations and maintenance expenses in the current year quarter. Other operations and maintenance expenses increased $5 million in the six months ended June 30, 2005, compared with the same period of 2004, primarily as a result of increased power plant maintenance costs due to a major power plant maintenance outage in the first quarter of 2005.
CILCORP’s and CILCO’s other operations and maintenance expenses both decreased $8 million in the second quarter of 2005 and decreased $9 million and $11 million, respectively, for the six months ended June 30, 2005, as compared with the same periods in 2004, primarily due to reduced power plant maintenance.
Other operations and maintenance expenses at IP increased $8 million in the three months ended June 30, 2005, as compared to the prior year period, primarily because of higher labor costs and increased overhead costs associated with the integration of systems and operations with Ameren. Other operations and maintenance expenses were comparable for the first six months of 2005 to the same period in 2004.
Depreciation and Amortization
Ameren’s depreciation and amortization expenses increased $25 million in the three months and $52 million in the six months ended June 30, 2005, compared with the same periods of 2004, because of the acquisition of IP, which added $19 million and $40 million to each period, respectively. Capital additions also resulted in increased depreciation expenses in the current year.
Depreciation and amortization expenses at UE increased $2 million in the three months and $6 million in the six months of the current year, as compared with the same periods of 2004, because of capital additions, partially offset by reduced depreciation on property transferred to CIPS in the Illinois service territory transfer.
CIPS’ depreciation and amortization expense increased $5 million in the second quarter and six-month period ended June 30, 2005, compared with the same periods of 2004, because of depreciation on property transferred from UE in the Illinois service territory transfer as well as capital additions.
Depreciation and amortization expenses at CILCORP increased $1 million in the three months and $3 million in the six months ended June 30, 2005, compared with the same periods of 2004, because of capital additions.
Depreciation and amortization expenses at Genco and CILCO were comparable for the second quarter and first six months of 2005 with the same periods in 2004.
IP’s depreciation and amortization expenses, excluding the amortization of regulatory assets, were comparable in the
three months and six months ended June 30, 2005, with the same periods of 2004. Amortization of regulatory assets at IP decreased $10 million in the three months and $21 million for the six months ended June 30, 2005, as compared with the same periods of 2004. The transition cost regulatory asset was eliminated in conjunction with Ameren’s acquisition of IP.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $21 million in the second quarter and $32 million in the six months of the current year, compared with the same periods of 2004, principally because of the acquisition of IP, which added $18 million and $40 million, respectively. Excluding IP in the current year, taxes other than income taxes at Ameren increased $3 million for the second quarter primarily because of higher property taxes, but decreased $8 million for the first six months of 2005 because of decreased gross receipts taxes of $4 million and decreased property taxes of $4 million as discussed below.
UE’s taxes other than income taxes increased in both the three months and six months ended June 30, 2005, as compared with the same periods in 2004, primarily because of increased property taxes due to higher assessments.
Taxes other than income taxes at CIPS increased for the second quarter compared to the same period in the prior year primarily because of increased property taxes, but were comparable for the six-month period in 2005 to the same period in the prior year.
Genco’s taxes other than income taxes were comparable in the three months, but decreased $8 million in the six months ended June 30, 2005, compared with the same periods of 2004, due to a favorable property tax court decision in the first quarter of 2005.
Both CILCORP’s and CILCO’s taxes other than income taxes decreased in the six months ended June 30, 2005, compared with the same periods of 2004, primarily because of reduced gross receipts taxes, but were comparable for the second quarter of 2005 compared to the same period in 2004.
Taxes other than income taxes at IP increased in the three months and six months ended June 30, 2005, compared with the same periods of 2004, primarily because of higher gross receipts taxes.
Other Income and Deductions
Other income and deductions decreased $3 million in the second quarter and $4 million in the first six months of the current year, compared with the same periods of 2004. Excluding IP in the current year, other income and deductions at Ameren decreased $4 million and $7 million in the respective periods. The decreases were primarily because of reduced interest income as a result of the investment of equity issuance proceeds in the prior year and other items discussed below.
Other income and deductions at UE was comparable in the three months ended June 30, 2005, with the same period in 2004, primarily because of a derivative loss in the prior year, and increased $3 million in the six months ended June 30, 2005, compared with the same period in 2004, primarily because of an increase in allowance for funds used during construction as a result of capital additions.
CIPS’ other income and deductions decreased $5 million in the second quarter and $7 million in the first six months of 2005, compared with the same periods of 2004, primarily because of reduced interest income on the intercompany note receivable from Genco.
Other income and deductions at CILCORP decreased $2 million in the three months ended June 30, 2005, and $3 million in the six months ended June 30, 2005, compared with the same periods in 2004, primarily because of the write-off of unrecoverable natural gas cost.
Other income and deductions at IP decreased $47 million in the quarter and $93 million in the six months ended June 30, 2005, compared with the same periods of 2004, primarily because of reduced interest income after the elimination of IP’s Note Receivable from Former Affiliate in conjunction with Ameren’s acquisition of IP.
Other income and deductions at Genco and CILCO were comparable in the three months and six months ended June 30, 2005, with the same periods of 2004.
Interest
Interest expense increased at Ameren in the three months and six months ended June 30, 2005, compared with the same periods of 2004 principally due to the acquisition of IP, which added $11 million for the second quarter and $21 million for the first six months of 2005. Excluding the IP results in the current year, interest expense was comparable to the same periods in 2004.
Genco’s interest expense decreased $5 million in the three months and $7 million in the six months ended June 30, 2005, compared with the same periods of 2004, primarily because of a reduction in principal amounts outstanding on intercompany promissory notes to CIPS and Ameren.
Interest expense at IP decreased $29 million in the three months and $58 million in the six months ended June 30, 2005, compared with the same periods of 2004, primarily because of redemptions and repurchases of indebtedness of
$700 million in the fourth quarter of 2004 and $70 million in 2005 and reductions in notes payable to IP SPT.
Interest expense at UE, CIPS, CILCORP and CILCO in the three months and six months ended June 30, 2005, was comparable to the same periods of 2004.
Income Taxes
Income tax expense at Ameren increased $40 million in the second quarter and $52 million in the first six months of the current year, compared with the same periods of 2004, because of higher pretax income primarily due to the inclusion of IP results in 2005, partially offset by the recognition in 2005 of a deduction allowed under the Jobs Creation Act. The second quarter of 2005 was also higher due to the timing of recording of the nontaxable federal Medicare Prescription Drug Subsidy in the prior year. Income tax expense was higher at UE, Genco, CILCORP and CILCO in the second quarter and first six months of 2005, compared with the same periods in 2004, due to higher pretax income. UE’s income tax expense was partially reduced in the current year by the recognition of the Jobs Creation Act deduction, but was increased in the second quarter of 2005, as compared to the prior year, by the timing of recording of the Medicare Prescription Drug Subsidy. Income tax expense decreased at CIPS and IP in the three months and six months ended June 30, 2005, compared with the same periods of 2004, due to lower pretax income and, in the case of CIPS, a reduction in estimates for anticipated settlements of uncertain tax positions.
LIQUIDITY AND CAPITAL RESOURCES
The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO 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 cash flows from operating activities, Genco principally relies on sales to an affiliate under a contract expiring at the end of 2006 and sales to other wholesale and industrial customers under long-term contracts. In addition, we plan to use short-term borrowings to support normal operations and other temporary capital requirements.
The following table presents net cash provided by (used in) operating, investing and financing activities for the six months ended June 30, 2005 and 2004:
| | Net Cash Provided By Operating Activities | | Net Cash Provided By (Used In) Investing Activities | | Net Cash Provided By (Used In) Financing Activities | |
| | | 2005 | | | 2004 | | | Variance | | | 2005 | | | 2004 | | | Variance | | | 2005 | | | 2004 | | | Variance | |
Ameren(a) | $ | 661 | | $ | 436 | | $ | 225 | | $ | (443 | ) | $ | (367 | ) | $ | (76 | ) | $ | (260 | ) | $ | 331 | | $ | (591 | ) |
| UE | | 355 | | | 274 | | | 81 | | | (494 | ) | | (254 | ) | | (240 | ) | | 92 | | | (20 | ) | | 112 | |
| CIPS | | 96 | | | 62 | | | 34 | | | - | | | 28 | | | (28 | ) | | (97 | ) | | (103 | ) | | 6 | |
| Genco | | 62 | | | 82 | | | (20 | ) | | 172 | | | (28 | ) | | 200 | | | (235 | ) | | (56 | ) | | (179 | ) |
| CILCORP | | 35 | | | 103 | | | (68 | ) | | (44 | ) | | (69 | ) | | 25 | | | 5 | | | (40 | ) | | 45 | |
| CILCO | | 57 | | | 94 | | | (37 | ) | | (47 | ) | | (72 | ) | | 25 | | | (11 | ) | | (27 | ) | | 16 | |
IP(b) | | 149 | | | 177 | | | (28 | ) | | 8 | | | (62 | ) | | 70 | | | (157 | ) | | (90 | ) | | (67 | ) |
(a) Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP.
(b) 2004 amounts include predecessor information.
Cash Flows from Operating Activities
Cash flows provided by operating activities increased for Ameren, UE and CIPS in the six months ended June 30, 2005, compared with the same period of 2004. Ameren’s increase of $225 million was primarily attributable to $149 million of cash from operations of IP, which was acquired on September 30, 2004. Excluding IP, Ameren’s cash from operations increased $76 million, which was primarily due to additional income of $55 million and deferred income tax expense of $27 million, which resulted in lower taxes paid. Significant working capital changes in the current period included the purchase of SO2 emission allowances of $92 million in 2005 and the absence in 2005 of $18 million of cash flows in 2004 from a coal contract settlement. Other working capital changes were primarily the result of timing differences.
An increase in UE’s electric margins and reduced other operations and maintenance expenses, as discussed under Results of Operations, contributed to a $28 million increase in net income before depreciation and amortization and cash flow from operations activities. Tax payments also decreased $24 million compared to the same period in 2004 principally due to the timing of payments benefiting cash flows from operating activities. In the six months ended June 30, 2004, UE’s cash flows from operating activities were higher due to the receipt of $18 million related to a coal contract settlement. Timing differences related to working capital also contributed
to UE’s cash flows for the six months ended June 30, 2005 compared to the same period last year.
CIPS’ increase in cash flows from operating activities in the six months ended June 30, 2005, was principally due to timing differences related to working capital for the six months ended June 30, 2005 compared to the same period last year.
Cash flows provided by operating activities decreased for Genco in the six months ended June 30, 2005, compared with the same period of 2004. Purchases of SO2 emission allowances and increased coal inventories accounted for a $68 million decrease in materials and supplies cash flow for the six months ended June 30, 2005 compared to the same period in 2004. These decreases in cash flows from operating activities were partially offset by differences in the timing and amount of accounts and wages payable, along with incremental electric margins as discussed under Results of Operations.
Cash flows from operating activities decreased for CILCORP and CILCO in the six months ended June 30, 2005, compared with the same period in 2004. Contributing to the reduction in cash flows from operating activities were purchases of SO2 emission allowances of $20 million and a decrease in deferred income tax expense of $16 million. Differences in the timing and amount of accounts and wages payable and accounts receivable also contributed to CILCORP’s and CILCO’s decrease in cash flows from operating activities. These decreases were partially offset by increased electric margins as discussed under Results of Operations.
IP’s decrease in cash flows provided by operations is due primarily to increased cash purchased power costs and the elimination of the Note Receivable from affiliate, partially offset by lower cash interest expense as discussed under Results of Operations.
Cash Flows from Investing Activities
Cash flows used in investing activities increased for Ameren and UE and decreased for CILCORP and CILCO for the six months ended June 30, 2005, compared with the same period in 2004. Investing activities were a source of cash for IP and Genco in the first six months of 2005 as compared to a use of cash in the first six months of 2004. CIPS’ cash flows from investing activities decreased from the year-ago period.
Ameren’s increase in cash used in investing activities was primarily due to additional capital expenditures of $61 million at IP.
UE’s capital expenditures included $241 million for 550 megawatts of CTs purchased from Genco. Otherwise, UE’s capital expenditures were flat in the six months ended June 30, 2005, compared with the same period in 2004. UE’s 2005 capital expenditures also included $25 million for a 117 megawatt CT from Development Company and related equipment from Resources Company.
CIPS’ cash flows from investing activities for the six months ended June 30, 2005 decreased compared to the year-ago period to $28 million advanced to the money pool in 2005.
Genco’s cash flows provided by investing activities increased in the six months ended June 30, 2005, compared with the same period in 2004, because of the sale of 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois to UE for $241 million. These proceeds were partially offset by incremental capital, expenditures and net advances to the money pool. Genco’s higher capital expenditures were attributed to upgrades at one of its power plants in the first quarter of 2005.
CILCORP’s and CILCO’s cash flows used in investing activities decreased in the six months ended June 30, 2005, compared with the same period in 2004 primarily because of reduced capital expenditures. In 2004, AERG made capital expenditures for significant power plant upgrades to increase fuel supply flexibility for power generation.
IP’s cash flows from investing activities increased in the six months ended June 30, 2005, primarily because of cash received from repayment of money pool advances.
Intercompany Transfer of Illinois Service Territory
On May 2, 2005, UE completed the transfer of its Illinois-based electric and natural gas utility businesses to CIPS, at a net book value of $133 million. UE transferred 50 percent of the assets directly to CIPS in consideration for a CIPS subordinated promissory note in the principal amount of approximately $67 million and 50 percent of the assets by means of a dividend in kind to Ameren, followed by a capital contribution by Ameren to CIPS. See Note 3 - Rate and Regulatory Matters, under Part I, Item 1 of this report for a discussion of the asset transfer.
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 may be purchased, among other things. 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.
See Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for a discussion of environmental matters.
Cash Flows from Financing Activities
Cash flows from financing activities decreased for Ameren in the six months ended June 30, 2005, as compared with the same period of 2004, primarily because of the receipt of $935 million related to common stock issuances in the first six months of 2004. These proceeds were used to fund the acquisition of IP and Dynegy’s 20% interest in EEI on September 30, 2004. In 2005, total common stock proceeds of $402 million included $345 million from the issuance of 7.4 million shares of common stock related to the settlement of a stock purchase obligation in Ameren’s adjustable conversion-rate equity security units. Short term debt redemptions increased by $130 million for the first six months of 2005 compared to the same period last year. In 2005, the absence of a $67 million UE nuclear fuel lease payment partially offset the decreases in cash from financing activities.
UE’s cash flows from financing activities increased in the six months ended June 30, 2005, compared with the same period of 2004. This increase was caused, in part, by a net increase in money pool borrowings, lower redemptions of long-term debt, a decrease in the payment of dividends to Ameren and the absence of a nuclear fuel lease payment that was made in the first three months of 2004. These increases were partially offset by higher redemptions of short-term debt, and lower issuances of long-term debt.
CIPS’ cash flows used in financing activities decreased slightly in the six months ended June 30, 2005, as compared with the same period of 2004. A $19 million cash benefit from reduced dividends paid to Ameren was offset by increased redemptions of long-term debt of $20 million.
Genco’s cash flows used in financing activities increased in the six months ended June 30, 2005, as compared with the same period of 2004, primarily because of a net change in money pool borrowings of $148 million, repayment of its $34 million note payable to Ameren, and payment of $52 million on its note payable to CIPS. The funds for these note repayments came from the $241 million in proceeds from the May 2005 asset sale of 550 megawatts of CTs to UE.
Effective May 1, 2005, Genco and CIPS amended certain terms of Genco’s subordinated affiliate note payable to CIPS by the issuance to CIPS of an amended and restated subordinated promissory note in the principal amount of approximately $249 million with an interest rate of 7.125% per annum, a 5-year amortization schedule and a maturity of May 1, 2010.
CILCORP’s and CILCO’s cash flows used in financing activities decreased in the six months ended June 30, 2005, compared with the same period of 2004. CILCORP’s net increase in the use of cash for money pool borrowings of $169 million for the first six months of 2005 compared to the same period in 2004 was partially offset by a capital contribution from Ameren in the amount of $101 million. There were no significant debt redemptions in 2005 compared to 2004 debt redemptions of $120 million and $100 million at CILCORP and CILCO, respectively. Dividend payments to Ameren increased $12 million and $10 million for CILCORP and CILCO, respectively, for the first six months of 2005 compared to the same period in 2004.
IP’s cash flows used in financing activities increased in the six months ended June 30, 2005, compared with the same period of 2004 primarily because of incremental redemptions, repurchases and maturities of long-term debt of $70 million and dividend payments of $40 million made to Ameren in 2005, partially offset by a decrease in prepaid interest on a note receivable from a former affiliate.
Short-term Borrowings and Liquidity
For information on short-term borrowing activity, relevant interest rates, and borrowings under Ameren’s utility money pool arrangement and non-state-regulated subsidiary money pool arrangement, see Note 4 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report.
The following table presents the various committed bank credit facilities of certain of the Ameren Companies and EEI subsequent to the changes to the credit facilities effective July 14, 2005. See Note 4 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report for additional information concerning the changes to these credit facilities.
Credit Facility | Expiration | Amount Committed | Amount Available |
Ameren:(a) | | | |
Multiyear revolving(b) | July 2010 | $ 1,150 | $ 1,075 |
Multiyear revolving | July 2010 | 350 | 350 |
EEI: | | | |
One bank credit facility | April 2006 | 20 | - |
Total | | $ 1,520 | $ 1,425 |
| (a) | Ameren Companies may access these credit facilities through intercompany borrowing arrangements. |
| (b) | UE, CIPS, CILCO, Genco and IP are direct parties to this agreement. |
In addition to committed credit facilities, a further source of liquidity for Ameren from time to time is available cash and cash equivalents. At June 30, 2005, Ameren had $27 million of cash and cash equivalents.
Ameren and UE are authorized by the SEC under the PUHCA to have an aggregate of up to of $1.5 billion and $1 billion, respectively, of short-term unsecured debt instruments outstanding at any time. The aggregate amount of short-term borrowings outstanding at any time at IP may not exceed $500 million pursuant to authorizations from the ICC and the SEC under the PUHCA. In addition, CIPS, CILCORP and CILCO have PUHCA authority to have an aggregate of up to $250 million each of short-term unsecured debt instruments outstanding at any time. Genco is authorized by the FERC to have up to $300 million of short-term debt outstanding at any time.
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 and preferred stock for the six months ended June 30, 2005 and 2004, for certain of the Ameren Companies. For additional information, see Note 5 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report.
| | Month Issued, Redeemed, Repurchased or Matured | Six Months |
2005 | 2004 |
Issuances | | | |
Long-term debt | | | |
UE: | | | |
5.00% Senior secured notes due 2020 | January | $ 85 | $ - |
5.50% Senior secured notes due 2014 | May | - | 104 |
Total Ameren long-term debt issuances | | $ 85 | $ 104 |
| | | | |
Common stock | | | |
Ameren: | | | |
7,402,320 Shares at $46.61(a) | May | $345 | $ - |
19,063,181 Shares at $45.90 | February | - | 875 |
DRPlus and 401(k)(b) | Various | 57 | 60 |
| Total common stock issuances | | $402 | $ 935 |
| Total Ameren long-term debt and common stock issuances | | $487 | $1,039 |
Redemptions, Repurchases and Maturities | | | |
Long-term debt | | | |
Ameren: | | | |
Senior notes due 2007(c) | February | $ 95 | $ - |
UE: | | | |
7.00% First mortgage bonds due 2024 | June | - | 100 |
CIPS: | | | |
6.49% First mortgage bonds due 2005 | June | 20 | - |
CILCORP: | | | |
8.70% Senior notes due 2009 | May | 6 | |
9.375% Senior bonds due 2029 | May | - | 20 |
CILCO: | | | |
Secured bank term loan | February | - | 100 |
EEI: | | | |
2000 Bank term loan, 7.61% due 2004 | June | - | 40 |
IP: | | | |
6.75% First mortgage bonds due 2005 | March | 70 | - |
Note payable to IP SPT | | | |
5.38% Series due 2005 | Various | 46 | 43 |
Less: IP activity prior to acquisition date | | - | (43) |
| Total Ameren long-term debt redemptions, repurchases and maturities | | $237 | $ 260 |
| (a) | Includes issuances of common stock of 1.2 million shares during the six months ended June 30, 2005 under DRPlus and 401(k) plans. |
| (b) | Shares issued upon settlement of the purchase contracts which were a component of the adjustable conversion-rate equity security units. See Note 5 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report. |
| (c) | Component of the adjustable conversion-rate equity security units. See Note 5 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report. |
The following table presents the authorized amounts under SEC shelf registration statements filed and declared effective for certain of the Ameren Companies as of June 30, 2005:
| | Effective Date | Authorized Amount | Issued | Available |
Debt: | | | | |
| Ameren | July 2004 | $2,000 | $459 | $1,541 |
UE(a) | September 2003 | 1,000 | 689 | 311 |
| CIPS | May 2001 | 250 | 150 | 100 |
| (a) | UE issued securities totaling $300 million in July 2005 leaving $11 million of securities currently available for issuance. |
Ameren also has approximately 7 million shares of common stock available for issuance under various other SEC effective registration statements applicable to our DRPlus and 401(k) plans as of June 30, 2005.
Ameren, UE and CIPS may sell all or a portion of the remaining securities registered under the registration statements if market conditions and capital requirements warrant such a sale. Any such offer and sale will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.
Indebtedness Provisions, Other Covenants and Off-Balance Sheet Arrangements
See Note 4 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report for a discussion of the covenants and provisions contained in certain of the Ameren Companies’ bank credit facilities. Also see Note 5 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report for a discussion of off-balance sheet arrangements and of covenants and provisions contained in certain of the Ameren Companies’ indenture agreements and articles of incorporation.
At June 30, 2005, the Ameren Companies were in compliance with their credit agreement indenture and articles of incorporation provisions and covenants.
We rely on access to short-term and long-term capital markets as a significant source of funding for capital requirements not satisfied by our operating cash flows. Our inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively impact our ability to maintain and grow our businesses. 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. Such events might cause our cost of capital to increase or our ability to access the capital markets to be adversely affected.
Dividends
The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. The board of directors has not set specific targets or payout parameters when declaring common stock dividends. However, the board considers various issues including Ameren’s historic earnings and cash flow, projected earnings, cash flow and potential cash flow requirements, dividend payout rates at other utilities, return on investments with similar risk characteristics and overall business considerations. Dividends paid by Ameren to stockholders during the first six months of 2005 totaled $253 million, or $1.27 per share (2004 - $232 million or $1.27 per share).
UE’s preferred stock dividends are payable August 15, 2005, to shareholders of record on July 20, 2005. CIPS’ preferred stock dividends are payable September 30, 2005, to shareholders of record on September 8, 2005. CILCO paid a preferred stock dividend of approximately $1 million on July 1, 2005. IP paid a preferred stock dividend of approximately $1 million on August 1, 2005.
Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, restrict the Ameren Companies’ payment of dividends. UE would experience restrictions on dividend payments if it were to extend or defer interest payments on its subordinated debentures. CIPS has provisions in its articles of incorporation restricting dividend payments based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Genco’s indenture includes restrictions that prohibit making any dividend payments if debt service coverage ratios are below a defined threshold. CILCORP has restrictions if leverage ratio and interest coverage ratio thresholds are not met or if CILCORP’s senior long-term debt does not have specified ratings as described in its indenture. CILCO has restrictions on dividend payments relative to the ratio of its balance of retained earnings to the annual dividend requirement on its preferred stock and amounts to be set aside for any sinking fund retirement of its 5.85% Series preferred stock. At June 30, 2005, none of the conditions described above that would restrict the payment of dividends existed. In its approval of the acquisition of IP by Ameren, the ICC issued an order that provides for the ability of IP to pay dividends on its common stock subject to certain conditions related to credit ratings of IP and Ameren and the elimination of IP’s 11.50% mortgage bonds. Given the current credit ratings of IP and the amount of IP’s 11.50% mortgage bonds that remain outstanding, IP’s payment of dividends on its common stock is restricted to $80
million in 2005 and $160 million cumulatively through 2006. In addition, in accordance with the order issued by the ICC, IP will establish a dividend policy comparable to the dividend policy of Ameren’s other Illinois utilities and consistent with achieving and maintaining a common equity to total capitalization ratio between 50% and 60%.
The following table presents dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents for the six months ended June 30, 2005 and 2004:
| | Six Months | |
| | 2005 | | 2004 | |
| UE | $ | 135 | | $ | 145 | |
| CIPS | | 9 | | | 28 | |
| Genco | | 34 | | | 35 | |
CILCORP(a) | | 30 | | | 18 | |
IP(b) | | 40 | | | - | |
| Non-Registrants | | 5 | | | 6 | |
| Dividends paid by Ameren | $ | 253 | | $ | 232 | |
(a) CILCO paid dividends of $20 million and $10 million for the six months ended June 30, 2005 and 2004, respectively.
(b) Prior to October 2004, the ICC prohibited IP from paying dividends. If permitted to be paid, IP’s dividends would have been paid directly to Illinova and therefore indirectly to
Dynegy.
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 Ameren Companies’ combined Form 10-K for the fiscal year ended December 31, 2004. See Note 12 - Pension and Other Postretirement 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, 2004, obligations related to the procurement of coal and natural gas increased at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $4,639 million, $1,812 million, $278 million, $1,082 million, $745 million, $745 million and $316 million, respectively, as of June 30, 2005. Total other obligations at December 31, 2004, updated for material changes since year-end through June 30, 2005, at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP are $5,062 million, $1,967 million, $522 million, $1,082 million, $770 million, $770 million and $617 million, respectively.
Credit Ratings
On March 31, 2005, Moody’s upgraded IP’s credit ratings. IP’s senior secured debt rating was upgraded from Baa3 to Baa1, its issuer rating was upgraded from Ba1 to Baa2, and its preferred stock rating was upgraded from Ba3 to Ba1. This rating action concluded Moody’s review for possible upgrade that was initiated for these ratings on March 18, 2005. The ratings outlook for IP is now stable.
Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and/or increase the cost
of borrowings, resulting in a negative impact on earnings. At June 30, 2005, if UE, CIPS, Genco, CILCORP, CILCO or IP were to receive a sub-investment-grade rating (less than BBB- or Baa3), Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP could have been required to post collateral for certain trade obligations amounting to $98 million, $28 million, $1 million, $12 million, $1 million, $1 million, and $29 million, respectively. In addition, the cost of borrowing under our credit facilities can increase or decrease based on credit ratings. A credit rating is not a recommendation to buy, sell or hold securities and it should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the assigning rating organization.
OUTLOOK
Below are some key trends that may impact the Ameren Companies’ financial condition and results of operation in 2005 and beyond:
Revenues
| · | Electric rates for Ameren’s operating subsidiaries have been fixed or declining for periods ranging from 12 years to 22 years. In 2006, electric rate adjustment moratoriums and intercompany power supply contracts expire in Ameren’s regulatory jurisdictions. Approximately 8 million megawatthours supplied annually by Genco and 6 million megawatthours supplied annually by AERG have been subject to contracts to provide CIPS and CILCO, respectively, with power. The prices in these power supply contracts of $34.00 per megawatthour for AERG and $38.50 per megawatthour for Genco were below estimated market prices for similar contracts in July 2005. CIPS, CILCO and IP have made filings with the ICC, in 2005, outlining, among other things, a proposed framework for generation procurement after 2006. In 2005, Ameren will also begin the process of preparing utility cost-of-service studies to be submitted in Illinois and Missouri in late 2005 to |
determine rates for UE, CIPS, CILCO and IP. In March 2005 legislative hearings, Ameren indicated it expected the average rates for its Illinois utilities, on a combined basis, may increase by 10% to 20% in 2007 over present bundled rate levels, with 50% to 70% of this increase resulting from higher power costs. This estimate was based on a number of assumptions about market prices for power, which were based on 2005 prices at that time, the type of power supply product to be procured, future auction results, ratemaking outcomes and various other factors. The final results of the auction process and regulatory proceedings could be significantly different from these assumptions. Based on the results of a cost of service study that will be submitted by UE by the end of 2005 and the status of the environmental and fuel cost recovery rulemaking proceedings, UE will determine what course of action it believes should be taken in resetting electric rates for Missouri. The MoPSC staff and other stakeholders will also review the study and, based upon their analyses, may also make rate recommendations. See Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.
| · | We expect continued economic growth in our service territory to benefit electric demand in 2005. |
| · | UE, Genco and CILCO are also seeking to raise the equivalent availability and capacity factors of power plants from 2004 levels. |
| · | In 2005, we expect natural gas and coal prices to support power prices in excess of 2004 levels. Power prices in the Midwest affect the amount of revenues UE, Genco and CILCO (through AERG) can generate by marketing any excess power into the interchange markets and influence the cost of power we purchase in the interchange markets. |
| · | On April 1, 2005, the MISO Day Two Markets began operating. The Day Two markets present an opportunity for increased power sales from UE, Genco and CILCO power plants and improved access to power for UE, CIPS, CILCO and IP, but also higher MISO-related costs. During initial MISO Day Two operations, we experienced what we believed was suboptimal dispatching of power plants and some price volatility, which have improved. |
Fuel and Purchased Power
| · | In 2004, 86% of Ameren’s electric generation (UE-80%, Genco-93%, CILCO-99%) was supplied by its coal-fired power plants and approximately 85% of the coal used by these plants (UE-97%, Genco-66%, CILCO-26%) was delivered by railroads from the Powder River Basin (“PRB”) in Wyoming. On May 7 and 8, 2005, the joint Burlington Northern-Union Pacific rail line in the PRB suffered two derailments due to unstable track conditions. As a result, the Federal Rail Administration placed slow orders, or speed restrictions, on sections of the line until the track could be made safe. These actions reduced deliveries of coal from PRB mines. Because of the railroad delivery problems, UE expects to receive about 85 to 90% of scheduled deliveries of PRB coal until track repairs are complete and the slow orders are removed. The railroads are projecting that maintenance of the joint rail line will be completed in November 2005 and normal deliveries should resume at that time. |
Ameren, UE, Genco and CILCO believe they have sufficient coal inventories to maintain generation at all coal plants through the maintenance period at the projected delivery levels. In order to reduce coal inventory shortage risk should other variations in deliveries occur, Ameren, UE, Genco and CILCO are implementing a coal management strategy. This strategy includes reducing sales of power during low-margin periods and purchasing economically available coal in the spot market. Actual power plant performance, power market conditions, weather-induced demand for power, availability of alternative coal supplies and the actual time required for the railroads to resume normal deliveries of PRB coal could have a significant impact on the effectiveness of these strategies.
| · | Ameren’s coal and related transportation costs rose in 2004 and are expected to increase 3% to 5% in 2005, an additional 5% to 10% in 2006, and to increase again by 10% to 15% in 2007. See Item 3 - Quantitative and Qualitative Disclosures about Market Risk for information about the percentage of coal and transportation requirements that are price-hedged for 2005 through 2009. |
| · | In July 2005 a new law was enacted that will enable the MoPSC to put in place an environmental cost recovery mechanism for Missouri’s utilities. In addition, it will enable the MoPSC to allow electric utilities to recover fuel and purchased power costs through a similar recovery mechanism. The legislation also includes rate case filing requirements, a 2.5% annual rate increase cap for the environmental recovery mechanism and prudency reviews, among other things. |
Other Costs
| · | UE’s Callaway nuclear plant will have a refueling and maintenance outage beginning in September 2005, which is expected to last 70 to 75 days. During this outage, major capital equipment will be replaced and upgraded providing a 60 megawatt increase in the generating capacity of the plant. As a result, the outage will last longer than a typical refueling outage, which usually lasts 30 to 35 days and occurs approximately every 18 months. During a refueling outage, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases versus non-outage years. |
| · | Over the next few years, we expect increased expenses for rising employee benefit costs as well as higher insurance and security costs associated with additional measures we have taken, or may have to take, at UE’s Callaway nuclear plant and our other operating plants. |
| · | We are currently undertaking cost reduction or control initiatives associated with the strategic sourcing of purchases and streamlining of administrative functions. |
Capital Expenditures
| · | The EPA has issued more stringent emission limits on all coal-fired power plants. Between 2005 and 2015, Ameren expects that certain of the Ameren Companies will be required to invest between $1.4 and $1.9 billion to retrofit their power plants with pollution control equipment. These investments will also result in higher ongoing operating expenses. Approximately two-thirds of this investment will be in Ameren’s regulated Missouri operations and therefore is expected to be recoverable over time from ratepayers. The recoverability of amounts expended in non-rate-regulated operations will depend on the adjustment of market prices for power as a result of this increased investment. |
| · | In June 2005, UE issued a request for proposal for the purchase of 500 to 800 megawatts of capacity and associated energy starting in 2006 through the acquisition of gas-fired, simple-cycle or combined-cycle electric generating resources currently operating in the MISO. UE is also evaluating its longer-term needs for new baseload and peaking electric generation capacity. |
Affiliate Transactions
| · | Due to the MoPSC order approving the Illinois service territory transfer or future regulatory proceedings, there could be changes to the agreement between UE and Genco to jointly dispatch electric generation or changes to the effect of that agreement on revenues and/or electric margins. Such changes could affect the pricing or availability of power transferred between Genco and UE. Based on operating performance for the past year, such changes would likely result in a transfer of electric margins from Genco to UE. The ultimate impact of any modifications to the joint dispatch agreement will be determined by future native load demand, the availability of electric generation from UE and Genco and market prices, among other things, but such impact could be material. Ameren’s earnings could be affected if electric rates for UE are adjusted by the MoPSC to reflect the provisions of the MoPSC order approving the service territory transfer and/or other changes to the joint dispatch agreement. See Note 3 - Rate and Regulatory Matters to our financial statements in Part 1, Item 1 of this report for a discussion of modifications to the joint dispatch agreement ordered by the MoPSC. |
Recent Acquisitions
| · | Ameren, CILCORP, CILCO and IP expect to continue to focus on realizing integration synergies associated with these acquisitions, including lower fuel costs at CILCORP and CILCO and reduced administrative and operating expenses at IP. |
Other
| · | In August 2005, the president signed into law the Energy Policy Act of 2005. This legislation includes several provisions that impact the Ameren Companies, including, among others, the repeal of the PUHCA effective in February 2005, under which Ameren is registered, and tax incentives for investments in pollution control equipment, electric transmission property, clean coal facilities and natural gas distribution lines. The Energy Policy Act of 2005 also extends the Price-Anderson nuclear plant liability provisions under the Atomic Energy Act of 1954. |
The outcome and developments related to 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, and liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s shareholder 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.
RISK FACTORS
Ameren may not be able to integrate IP successfully into its other businesses or achieve the benefits it anticipates.
Ameren cannot ensure that it will be able to integrate IP successfully with its other businesses. The integration of IP with its other businesses will present significant challenges; Ameren may not be able to operate the combined company as effectively as expected. Ameren may also fail to achieve the anticipated benefits of the acquisition as quickly or as cost-effectively as anticipated, or it may not be able to achieve those benefits at all. Ameren expects that this acquisition will be accretive to earnings per share in the first two years. This expectation is based on important assumptions, which may be incorrect, including assumptions related to expected financing arrangements, regulatory treatment, interest rates, market prices for power, and synergies. As a result, if Ameren is unable to integrate its businesses effectively or to achieve the benefits anticipated, its results of operations, financial position, and liquidity may be materially adversely affected.
The electric and gas rates that certain Ameren Companies are allowed to charge in Missouri and Illinois are largely set through 2006. These “rate freezes,” along with other actions of regulators that can significantly affect our earnings, liquidity and business activities, are largely outside our control.
The rates that certain Ameren Companies are allowed to charge for their services are the single most important item influencing the results of operations, financial position, and liquidity of the Ameren Companies. Our industry is highly regulated. The regulation of the rates that we charge our customers is determined, in large part, by governmental organizations outside of our control, including the MoPSC, the ICC, and the FERC. We are also subject to regulation by the SEC under the PUHCA. Decisions made by these regulators could have a material impact on our results of operations, financial position, and liquidity.
As a part of the settlement of UE’s Missouri electric rate case in 2002, UE is subject to a rate moratorium that prohibits changes in its electric rates in Missouri before July 1, 2006, subject to limited statutory and other exceptions. Furthermore, as part of the settlement of UE’s Missouri gas rate case, which was approved by the MoPSC on January 13, 2004, UE agreed to a rate moratorium. UE will make no changes in its gas delivery rates prior to July 1, 2006, subject to certain exceptions. Also, in the order approving Ameren’s acquisition of IP, the ICC prohibited IP from filing for any proposed increase in gas delivery rates to be effective prior to January 1, 2007, beyond IP’s then-pending request for a gas delivery rate increase. In addition, a provision of the Illinois legislation related to the restructuring of the Illinois electric industry put a rate freeze into effect in Illinois through January 1, 2007, for CIPS, CILCO and IP. This Illinois legislation also requires that 50% of the earnings from each respective Illinois jurisdiction in excess of certain levels be refunded to CIPS’, CILCO’s and IP’s Illinois customers through 2006. The ICC conducted workshops seeking input from interested parties on the framework to be used for retail rate determination and for generation procurement by customers after the current Illinois rate freeze and supply contracts end in 2006. In 2005, CIPS, CILCO and IP have made filings with the ICC outlining a proposed framework for a generation procurement auction and a rate mechanism to legislators to pass generation costs through to customers, among other things.
As a part of the settlement of UE’s Missouri electric rate case in 2002, UE also undertook to use commercially reasonable efforts to make critical energy infrastructure investments of $2.25 billion to $2.75 billion from January 1, 2002 through June 30, 2006. Ameren also committed IP to make between $275 million and $325 million in energy infrastructure investments over its first two years of ownership, in conjunction with the ICC’s approval of Ameren’s acquisition of IP. UE’s agreement to a rate moratorium in Missouri and CIPS’, CILCO’s and IP’s rate freezes mean that capital expenditures will not become recoverable in rates, and will not earn a return, before July 1, 2006, for UE and January 1, 2007, for CIPS, CILCO and IP. Therefore, undertakings with respect to energy infrastructure investments and funding new programs, coupled with the rate reductions and rate moratoriums, could result in increased financing requirements for UE, CIPS, CILCO and IP and thus have a material impact on our results of operations, financial position, and liquidity.
The Ameren Companies do not currently have in either Missouri or Illinois a fuel adjustment clause for their electric operations that would allow them to recover from customers, the costs for purchased power or increased fuel used for generation. Therefore, to the extent that we have not hedged our fuel and power costs, we are exposed to changes in fuel and power prices to the extent that fuel for our electric generating facilities and power must be purchased on the open market in order for us to serve our customers. See the Outlook section in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of Missouri legislation enabling a fuel adjustment clause.
Steps taken and being considered at the federal and state levels continue to change the structure of the electric industry and utility regulation. At the federal level, the FERC has been mandating changes in the regulatory framework for transmission-owning public utilities such as UE, CIPS, CILCO and IP. In Missouri, restructuring bills have been introduced in the past, but no legislation has been passed.
Principally because of rate reductions and rate moratoriums that affect certain Ameren Companies, increased costs and investments have resulted in decreased returns in our distribution utility businesses. In 2005, Ameren began the process for preparing and submitting proposals for utility rate adjustments in Illinois and Missouri to take effect after the expiration of the applicable rate moratoriums.
We are not able to predict what rate treatment certain Ameren Companies will receive after the rate moratoriums expire in Missouri and Illinois. See Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report. In response to competitive, economic, political, legislative and regulatory pressures, we may be subject to further rate moratoriums, rate refunds, limits on rate increases or rate reductions, any and all of which could have a significant adverse affect on our results of operations, financial position, and liquidity.
Increased federal and state environmental regulation will require UE, Genco and CILCO to incur large capital expenditures and increase operating costs.
Approximately 65% of Ameren’s generating capacity is coal-fired. The balance is nuclear, gas-fired, hydro, and oil-
fired. In March 2005, the EPA issued final regulations with respect to SO2, NOx, and mercury emissions from coal-fired power plants. These new rules will require significant additional reductions in these emissions from our power plants in phases, beginning in 2010. Preliminary estimates of capital costs, based on Ameren systems’ current technology, to comply with the EPA proposed SO2, NOx, and mercury emission regulations, range from $1.4 billion to $1.9 billion by 2015.
Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. Coal-fired power plants are significant sources of carbon dioxide emissions, a principal greenhouse gas. The related Kyoto Protocol was signed by the United States, but it has since been rejected by the president, who instead has asked for an 18% voluntary decrease in carbon intensity. In response to the administration’s request, six electric power sector trade associations, including the Edison Electric Institute, of which Ameren is a member, and the Tennessee Valley Authority (TVA), signed a Memorandum of Understanding (MOU) with the DOE in December 2004 calling for a 3% - 5% decrease in carbon intensity from the utility sector between 2002 and 2012 on a voluntary basis. Currently, Ameren is considering various initiatives to comply with the MOU. These include enhanced generation at our nuclear and hydro power plants, increased efficiency measures at our coal-fired units, and investing in renewable energy and carbon sequestration projects.
The EPA has been conducting an enforcement initiative in an effort to determine whether modifications at a number of coal-fired power plants owned by electric utilities in the U.S. are subject to New Source Review 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 made.
In April 2005, Genco 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 its Meredosia, Hutsonville, Coffeen and Newton facilities, EEI’s Joppa facility and AERG’s E.D. Edwards and Duck Creek facilities. All of these facilities are coal-fired plants. The information request requires Genco to provide responses to specific EPA questions regarding certain projects and maintenance activities in order to determine compliance with certain Illinois air pollution and emissions rules and with the New Source Performance Standard requirements of the Clean Air Act. Genco is fully complying with this information request, but cannot predict the outcome of this matter at this time.
We are unable to predict the ultimate effect of any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation on our results of operations, financial position, or liquidity. Any of these factors would add significant pollution control expenditures and operating costs to UE’s, Genco’s and CILCO’s generating assets and, therefore, could also increase financing requirements for some Ameren Companies. Although costs incurred by UE would be eligible for recovery in rates over time, subject to MoPSC approval in a rate proceeding, there is no similar mechanism for recovery of costs by Genco or CILCO in Illinois.
UE’s, CIPS’, CILCO’s and IP’s participation in the MISO could increase costs, reduce revenues, and reduce UE’s, CIPS’, CILCO’s and IP’s control over their transmission assets. Genco could also incur increased costs or reduced revenues as a result of participation in the MISO Day Two Markets.
On May 1, 2004, functional control of the UE and CIPS transmission systems was transferred to the MISO. On September 30, 2004, IP transferred functional control of its transmission system to the MISO. CILCO had transferred functional control of its transmission system to the MISO before its acquisition. Ameren, UE, CIPS, CILCO and IP may be required to incur expenses or expand their transmission systems according to decisions made by MISO rather than according to their internal planning process. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of the Ameren Companies’ combined Form 10-K for the fiscal year ended December 31, 2004.
The MISO Day Two Market, which began operation on April 1, 2005, is designed to result in improved transparency of power pricing and efficiency in generation dispatch. Since this is a new and complex market, there could be significant initial price volatility. In addition, the movement of power could result in unanticipated transmission congestion charges or credits.
Until we achieve some degree of operational experience participating in the MISO, including the MISO Day Two Market, we are unable to predict the impact that the MISO participation or ongoing RTO developments at the FERC or other regulatory authorities will have on our results of operations, financial position, or liquidity.
Increasing costs associated with our defined benefit retirement plans, health care plans, and other employee- related benefits may adversely affect our results of operations, financial position, and liquidity.
We have defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates, and
other actuarial assumptions have a significant impact on our earnings and funding requirements. Assuming that we continue to receive federal interest rate relief beyond 2005, we do not expect contributions to our defined benefit plans to be required until 2008 and 2009, when an aggregate $400 million is expected to be contributed. This amount is an estimate; it may change because of actual investment performance, changes in interest rates, or any pertinent changes in government regulations, any of which could also result in a requirement to record an additional minimum pension liability.
In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our defined benefit retirement plans, health care plans and other employee benefits may adversely affect our results of operations, financial position, or liquidity.
UE’s, Genco’s, CILCO’s, AERG’s, Medina Valley’s and EEI’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, and increased purchased power costs.
UE, Genco, CILCO, AERG, Medina Valley, and EEI own and operate coal, nuclear, gas-fired, hydro, and oil-fired generating facilities. Operation of electric generating facilities involves certain risks that can adversely affect energy output and efficiency levels. Included among these risks are:
| · | increased prices for fuel and fuel transportation; |
| · | facility shutdowns due to a failure of equipment or processes or operator error; |
| · | longer-than-anticipated maintenance outages; |
| · | disruptions in the delivery of fuel and lack of adequate inventories; |
| · | inability to comply with regulatory or permit requirements; |
| · | disruptions in the delivery of electricity; |
| · | increased capital expenditures requirements, including those due to environmental regulation; and |
| · | unusual or adverse weather conditions, including catastrophic events such as fires, explosions, floods or other similar occurrences affecting electric generating facilities. |
A substantial portion of Genco’s and CILCO’s generating capacity is committed under affiliate contracts that expire at the end of 2006. Upon expiration of these contracts, Genco’s and CILCO’s electric generating facilities must compete for the sale of energy and capacity, which exposes them to price risk.
As of June 30, 2005, Genco and CILCO, through AERG, owned 4,199 megawatts and 1,165 megawatts, respectively, of non-rate-regulated electric generating facilities. Of these non-rate-regulated electric generating facilities, approximately 3,700 megawatts are currently under full-requirements contracts with our affiliates. The remainder of the generating capacity must compete for the sale of energy and capacity.
To the extent electric capacity generated by these facilities is not under contract to be sold, the revenues and results of operations of these non-rate-regulated subsidiaries will generally depend on the prices that they can obtain for energy and capacity in Illinois and adjacent markets. Among the factors that could influence such prices (all of which are beyond our control to a significant degree) are:
| · | the current and future market prices for natural gas, fuel oil and coal; |
| · | current and forward prices for the sale of electricity; |
| · | the extent of additional supplies of electric energy from current competitors or new market entrants; |
| · | the pace of deregulation in our market area and the expansion of deregulated markets; |
| · | the regulatory and pricing structures developed for Midwest energy markets as they continue to evolve and the pace of development of regional markets for energy and capacity outside of bilateral contracts; |
| · | future pricing for, and availability of, transmission services on transmission systems, and the effect of RTOs and export energy transmission constraints, which could limit the ability to sell energy in markets adjacent to Illinois; |
| · | the rate of growth in electricity usage as a result of population changes, regional economic conditions, and the implementation of conservation programs; and |
| · | climate conditions prevailing in the Midwest market. |
In a report issued by the ICC in late 2004, a process was outlined that would have CIPS, CILCO and IP procuring power through an auction monitored by the ICC after the current Illinois rate freeze and supply contracts end in 2006. Genco and AERG, through Marketing Company, would probably participate in this auction, but there might be a limit on the maximum amount of power they could supply to Ameren’s Illinois utilities. See Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.
Genco and UE have signed an agreement to dispatch their generating facilities jointly, which produces benefits and efficiencies for both generating parties. Recently completed or future federal and state regulatory proceedings and policies may evolve in ways that could affect Genco’s ability to participate in these affiliate transactions on current terms. For example, as a result of the MoPSC order approving the transfer of UE’s Illinois-based utility business to CIPS, certain terms of the joint dispatch agreement were ordered to be
modified. Due to this MoPSC order or future regulatory proceedings, there could be changes to the joint dispatch agreement that would affect revenues and/or electric margins. Such changes could affect the pricing or availability of power transferred between Genco and UE. Based on operating performance for the past year, such changes would likely result in a transfer of electric margins from Genco to UE. The ultimate impact of any modifications to the joint dispatch agreement will be determined by future native load demand, the availability of electric generation from UE and Genco and market prices, among other things, but such impact could be material. Ameren’s earnings could be affected if electric rates for UE are adjusted by the MoPSC to reflect the provisions of the MoPSC order approving the service territory transfer and/or other changes to the joint dispatch agreement. See Note 3 - Rate and Regulatory Matters to our financial statements in Part 1, Item 1 of this report for a discussion of modifications to the joint dispatch agreement ordered by the MoPSC.
UE owns the Callaway nuclear plant, which represents approximately 13% of UE’s generation capacity. Therefore, UE is subject to the risks of nuclear generation, which include the following:
The NRC has broad authority under federal law to impose licensing and safety requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines, shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as UE’s. In addition, if a serious nuclear incident occurred, it could have a material but indeterminable adverse effect on UE’s results of operations, financial position, or liquidity. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.
Operating performance at UE’s Callaway nuclear plant has resulted in unscheduled or extended outages including the extension of Callaway’s scheduled refueling and maintenance outage in 2004. In addition, Ameren and UE incurred significant unanticipated replacement power and maintenance costs. As a result, the operating performance at UE’s Callaway nuclear plant has declined in comparison with both its past operating performance and the operating performance of other nuclear plants in the U.S. Ameren and UE are actively working to address the factors that led to the decline in Callaway’s operating performance. Management and supervision of operating personnel, equipment reliability, maintenance worker practices, engineering performance, and overall organizational effectiveness have been reviewed with some actions taken and other actions currently under consideration. However, Ameren and UE cannot predict whether such efforts will result in an overall improvement of operations at Callaway. Any actions taken are expected to result in incremental operating costs at Callaway. Further, additional unscheduled or extended outages at Callaway could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and UE.
We are exposed to changes in market prices for natural gas, fuel, electricity, and emission credits. Prices for natural gas, fuel, electricity, and emission credits may fluctuate substantially over relatively short periods of time and expose us to commodity price risk. We use long-term purchase and sales contracts in addition to derivatives such as forward contracts, futures contracts, options, and swaps to manage these risks. We attempt to manage our risk associated with these activities through enforcement of established risk limits and risk management procedures. We cannot assure that these strategies will be successful in managing our pricing risk, or that they will not result in net liabilities to us as a result of future volatility in these markets.
Although we routinely enter into contracts to hedge our exposure to the risks of demand, market effects of weather, and changes in commodity prices, we do not always hedge the entire exposure of our operations from commodity price volatility. Furthermore, our ability to hedge our exposure to
commodity price volatility depends on liquid commodity markets. As a result, to the extent the commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater unhedged positions than we would prefer at a given time. To the extent that unhedged positions exist, fluctuating commodity prices can adversely affect our results of operations, financial position, and liquidity.
We are exposed to risk that counterparties who owe us money, energy or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements (which include agreements for a subsidiary of Dynegy and others to supply electricity to IP during 2005 and 2006) fail to perform, we might be forced to replace the underlying commitment at then-current market prices. In such event, we might incur losses in addition to the amounts, if any, already paid to the counterparties.
Like other electric and gas utilities, our power generation plants, fuel storage facilities, and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues or significant additional costs to repair, which could have a material adverse effect on our results of operations, financial position, and liquidity.
We use short-term and long-term capital markets as a significant source of liquidity and funding for capital requirements, including those related to future environmental compliance, not satisfied by our operating cash flows. The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively impact our ability to maintain and expand our businesses. Based on our current credit ratings, we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets that could increase our cost of capital or impair our ability to access the capital markets.
See Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.
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 such as interest rates, commodity prices and equity security prices. 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 represented in the following discussion.
We are exposed to market risk through changes in interest rates. The following table presents the estimated increase (decrease) in our annual interest expense and net income if interest rates were to increase by 1% on variable rate debt outstanding at June 30, 2005:
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. On all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction.
Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables, executory contracts with market risk exposures, and leveraged lease investments. 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 June 30, 2005, no nonaffiliated customer represented greater than 10%, in the aggregate, of our accounts receivable. Our revenues are primarily derived from sales of electricity and natural gas to customers in Missouri and Illinois. UE, Genco and Marketing Company have credit exposure associated with accounts receivable from nonaffiliated companies for interchange power sales. At June 30, 2005, UE’s, Genco’s and Marketing Company’s combined credit exposure to non-investment-grade counterparties related to interchange sales was less than $1 million, net of collateral (2004 - $2 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 prior to entering into sales, forwards, swaps, futures or option contracts, and we monitor counterparty exposure associated with our leveraged leases. We are currently evaluating our credit exposure associated with the implementation of the MISO Day Two Markets on April 1, 2005. At June 30, 2005, we estimate this credit exposure to be $10 million.
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 could be reflected in net income and OCI, and the amount of cash required to be contributed to the plans.
The Ameren Companies are exposed to changes in market prices for natural gas, fuel and electricity to the extent they cannot be recovered through rates.
In the event of a significant increase in coal prices, UE, Genco and CILCO 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, the sensitivity analysis assumes no change in our financial structure or fuel sources.
See Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for further information.
As of June 30, 2005, the principal executive officer and principal financial officer of each of the Ameren Companies have evaluated 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 that evaluation, the principal executive officer and principal financial officer of each of the Ameren Companies have concluded that such disclosure controls and procedures are effective in timely alerting them to any material information relating to such Registrant that is required in such Registrant’s reports filed or submitted to the SEC under the Exchange Act and are effective in ensuring that information required to be disclosed in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
