The following table presents insurance coverage at UE’s Callaway nuclear plant at March 31, 2006:
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 and natural gas for distribution. 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 Annual Report on Form 10-K for the fiscal year ended December 31, 2005.
As of March 31, 2006, the commitments for the procurement of coal have changed from amounts previously disclosed as of December 31, 2005. The following table presents the total estimated coal purchase commitments at March 31, 2006:
| | 2006 | | 2007 | | 2008 | | 2009 | | 2010 | | Thereafter(a) | |
Ameren(b) | $ | 598 | | $ | 493 | | $ | 499 | | $ | 381 | | $ | 215 | | $ | 77 | |
| UE | | 339 | | | 285 | | | 250 | | | 201 | | | 147 | | | 77 | |
| Genco | | 125 | | | 94 | | | 148 | | | 130 | | | 36 | | | - | |
| CILCORP/CILCO | | 60 | | | 40 | | | 34 | | | 24 | | | 15 | | | - | |
| (a) | Commitments for coal are until 2011. |
| (b) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
As of March 31, 2006, the commitments for the procurement of natural gas have changed from amounts previously disclosed as of December 31, 2005. The following table presents the total estimated natural gas purchase commitments at March 31, 2006:
| | 2006 | | 2007 | | 2008 | | 2009 | | 2010 | | Thereafter(a) | |
Ameren(b) | $ | 524 | | $ | 511 | | $ | 361 | | $ | 209 | | $ | 123 | | $ | 212 | |
| UE | | 77 | | | 53 | | | 43 | | | 34 | | | 27 | | | 35 | |
| CIPS | | 91 | | | 116 | | | 87 | | | 58 | | | 39 | | | 107 | |
| Genco | | 16 | | | 25 | | | 20 | | | 8 | | | 8 | | | 12 | |
| CILCORP/CILCO | | 137 | | | 150 | | | 97 | | | 51 | | | 19 | | | 33 | |
| IP | | 184 | | | 158 | | | 112 | | | 57 | | | 28 | | | 25 | |
| (a) | Commitments for natural gas are until 2016. |
| (b) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
Environmental Matters
We are subject to various environmental laws and 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 laws and regulations address noise, emissions, and impacts to air and water, protected and cultural resources (such as wetlands, endangered species, and archeological and historical resources), and chemical and waste handling. Our activities often require complex and lengthy processes as we obtain approvals, permits or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires 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 our operations, as required. The more significant matters are discussed below.
Clean Air Act
In May 2005, the EPA issued final regulations with respect to SO2 and NOx emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean Air Mercury Rule) from coal-fired power plants. The new rules will require significant reductions in these emissions from UE, Genco, CILCO and EEI power plants in phases, beginning in 2009. States are required to finalize rules to implement the federal Clean Air Interstate Rule and Clean Air Mercury Rule by September and November 2006, respectively. 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 it may implement a more stringent program than the federal program. Illinois and Missouri are developing proposed rules that will be subjected to public review and comment. We do not expect the state regulations to be finalized until late 2006. In January 2006, the Illinois governor recommended that the Illinois EPA adopt rules for mercury significantly stricter than the federal rules. The process by which state rules will be drafted and determined is still in its early stages, but should stricter rules be adopted, they would change the overall environmental compliance strategy for UE’s, Genco’s, CILCO’s and EEI’s coal-fired power plants and increase or accelerate related costs from previous estimates. An implementation plan from Missouri regulators is still under review and consideration. The table below presents preliminary estimated capital costs based on current technology to comply with the federal Clean Air Interstate Rule and Clean Air Mercury Rule. The timing of estimated capital costs between periods at UE will be influenced by whether excess emission credits are used to comply with the proposed rules, thereby deferring capital investment.
| | 2006 | | 2007 - 2010 | | 2011 - 2016 | | Total | |
Ameren(a) | $ | 75 | | $ | 1,020 -1,405 | | $ | 1,015 - 1,400 | | $ | 2,110 - 2,880 | |
| UE | | 60 | | | 365 - 505 | | | 750 - 1,040 | | | 1,175 - 1,605 | |
| Genco | | 10 | | | 430 - 595 | | | 10 - 20 | | | 450 - 625 | |
| CILCO | | 5 | | | 175 - 245 | | | 145 - 200 | | | 325 - 450 | |
| EEI | | 5 | | | 55 - 75 | | | 130 - 180 | | | 190 - 260 | |
The costs reflected in the table assume that 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 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 action would have on our results of operations, financial position, or liquidity.
Emission Credits
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. The Clean Air Act and NOx Budget Trading Program created marketable commodities called allowances. Currently each allowance gives the owner the right to emit one ton of SO2 or NOx. All existing generating facilities have been allocated allowances that are based on past production and the statutory emission reduction goals. If additional allowances are needed for new generating facilities, they can be purchased from facilities that have excess allowances or from allowance banks. Our generating facilities comply with the SO2 limits through the use and purchase of allowances, through the use of low-sulfur fuels, and through the application of pollution control technology. The NOx Budget Trading Program limits emissions of NOx during the ozone season (May through September). The NOx Budget Trading Program has applied to all electric generating units in Illinois since the beginning of 2004; it will apply to the eastern third of Missouri, where UE’s coal-fired power plants are located, beginning in 2007. Our generating facilities are expected to comply with the NOx limits through the use and purchase of allowances or through the application of pollution control technology, including low-NOx burners, over-fire air systems, combustion optimization, rich reagent injection, selective noncatalytic reduction and selective catalytic reduction systems.
As of March 31, 2006, UE, Genco, CILCO and EEI held 1.89 million, 0.70 million, 0.34 million and 0.36 million, respectively, of SO2 emission allowances, with vintages from 2006 to 2016. Each company possesses additional allowances for use in periods beyond 2016. As of March 31, 2006, UE, Genco, CILCO, and EEI Illinois facilities held 249, 11,975, 2,178, and 2,859, respectively, of NOX emission allowances, with vintages from 2006 to 2008. As of March 31, 2006, the SO2 and NOx emission allowances for UE, Genco, CILCO and EEI were carried as intangible assets at a book value of $63 million, $96 million, $64 million and $41 million, respectively. The Illinois EPA has not yet issued any NOx emission allowance allocations for 2007 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 allowances for Missouri facilities will be 10,178 per season in 2007 and 2008 according to rules finalized in May 2005. New environmental regulations, including the Clean Air Interstate Rule, the timing of the installation of pollution control equipment and the level of operations will have a significant impact on the amount of allowances actually required for ongoing operations. The Clean Air Interstate Rule requires a reduction in SO2 emissions by requiring a change in the way Acid Rain Program allowances are surrendered. The current Acid Rain Program requires the surrender of one SO2 allowance for every ton of SO2 that is emitted. The Clean Air Interstate Rule program will require that SO2 allowances be surrendered at a ratio of two allowances for every ton of emission in 2010 through 2014. Beginning in 2015, the Clean Air Interstate Rule program will require SO2 allowances to be surrendered at a ratio of 2.86 allowances for every ton of emission.
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 United States 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 performed.
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 required Genco to provide responses to specific EPA questions regarding certain projects and maintenance activities to determine compliance with certain Illinois air pollution and emissions rules and with the New Source Performance Standard requirements of the Clean Air Act. This information request is being complied with, but we cannot predict the outcome of this matter.
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 degree 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 facilities 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 preexisting environmental contamination at the transferred sites.
As of March 31, 2006, 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 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, and costs are subject to annual reconciliation review by the ICC. As of March 31, 2006, CIPS, CILCO and IP had recorded liabilities of $25 million, $3 million and $62 million, respectively, to represent estimated minimum obligations.
In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one in Iowa. UE does not currently have a rate rider mechanism in effect in Missouri that permits remediation costs associated with MGP sites to be recovered from utility customers. See Note 2 - Rate and Regulatory Matters for information on a recently enacted law in Missouri enabling the MoPSC to put in place environmental cost recovery mechanisms for Missouri utilities. UE does not have any retail utility operations in Iowa which would provide a source of recovery of these remediation costs. 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 March 31, 2006, UE had recorded $10 million to represent its estimated minimum obligation for MGP sites. UE also is responsible for four electric sites in Missouri that have corporate cleanup liability, most as a result of federal agency mandates. As of March 31, 2006, UE had recorded $5 million to represent its estimated minimum obligation for these sites. 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. UE currently owns a parcel of property that was 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 issued by the EPA listing 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 Solutia’s former chemical waste landfill and the resulting impact area in the Mississippi River. UE was asked to participate in response to activities that involve the installation of a barrier wall around a chemical waste site and three recovery wells to divert groundwater flow. The projected cost for this remedy method ranges from $25 million to $30 million. In November 2002, UE sent a letter to the EPA asserting its defenses to the Unilateral Administrative Order and requesting 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 it 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.
The status of future remediation at Sauget Area 2 and compliance with the Unilateral Administrative Order is uncertain, so 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, it is possible that 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 to CIPS.
In December 2004, AERG submitted a comprehensive package to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek power plant facility. Information submitted by AERG is currently under review by the Illinois EPA. CILCORP and CILCO both have a liability of $3 million at March 31, 2006, included on their Consolidated Balance Sheets for the estimated cost of the remediation effort, which involves treating and discharging recycle-system water in order to address these groundwater and surface water issues.
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 activities may have on our results of operations, financial position, or liquidity.
Pumped-storage Hydroelectric Facility Breach
In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. The incident is being investigated by FERC and state authorities. UE expects the results of these reviews later in 2006. Preliminary reports issued by outside experts hired by UE to review the cause of the incident and by FERC staff, indicate design, construction and human error as causes of the breach. In their report, UE’s outside experts concluded that restoration of the upper reservoir, if undertaken, will require a complete rebuild of the entire dam with a completely different design concept, not simply a repair of the breached area. We expect that these reports will be considered in the final report issued by FERC. The facility will remain out of service until reviews by FERC and state authorities are concluded, further analyses are completed, and input is received from key stakeholders as to how and whether to rebuild the facility. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through most, if not all, of 2008.
UE has accepted responsibility for the effects of the incident. At this time, UE believes that substantially all of the damage and liabilities caused by the breach will be covered by insurance. UE expects the total cost for damage and liabilities resulting from the Taum Sauk incident to range from $53 million to $73 million. As of March 31, 2006, UE had paid $18 million and accrued a $35 million liability, while expensing $1 million for the insurance deductible and recording a $52 million receivable due from insurance companies. No amounts have been recognized in the financial statements relating to estimated costs to repair or rebuild the facility. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers.
As a result of this breach, UE may be subject to litigation by private parties or by state or federal authorities. Until the reviews conducted by state and federal authorities have concluded, the insurance review is completed, a decision whether the plant will be rebuilt is made and future regulatory treatment for the plant is determined, among other things, we are unable to determine the impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already accrued.
Asbestos-related Litigation
Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case is significant; as many as 129 parties are named in some pending cases and as few as six in others. However, in the cases that were pending as of March 31, 2006, the average number of parties is 65.
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 January 1, 2006, through March 31, 2006, seven additional asbestos-related lawsuits were filed against UE, CIPS, CILCO and IP, mostly in the Circuit Court of Madison County, Illinois. Three lawsuits were dismissed and three were settled. The following table presents the status as of March 31, 2006, 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 | | 303 | | | 30 | | | 161 | | | 121 | | | 2 | | | 32 | | | 141 | |
| Settled | | 93 | | | - | | | 48 | | | 38 | | | - | | | 9 | | | 47 | |
| Dismissed | | 140 | | | 22 | | | 91 | | | 46 | | | 2 | | | 4 | | | 62 | |
| Pending | | 70 | | | 8 | | | 22 | | | 37 | | | - | | | 19 | | | 32 | |
| (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 March 31, 2006, five 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 ICC order approving Ameren’s acquisition of IP effective September 30, 2004, also approved a tariff rider to recover the costs of IP’s asbestos-related litigation claims, subject to the following terms. Beginning in 2007, 90% of cash expenditures in excess of the amount included in base electric rates will be recovered by IP from a $20 million trust fund established by IP and
financed with contributions of $10 million each by Ameren and Dynegy. If cash expenditures are less than the amount in base rates, IP will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider.
The Ameren Companies believe that the final disposition of these proceedings will not have a material adverse effect on their results of operations, financial position, or liquidity.
NOTE 9 - 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 2015. 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. It is assumed that the Callaway nuclear plant site will be decommissioned based on immediate dismantlement method and removal from service. Ameren and UE have recorded an ARO for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are charged to the costs of service used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2005, 2004 and 2003. Every three years, the MoPSC requires UE to file an updated cost study for decommissioning its Callaway nuclear plant. Electric rates may be adjusted at such times to reflect changed estimates. The latest study was filed in 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 a regulatory asset.
NOTE 10 - 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 ended March 31, 2006 and 2005, is shown below for the Ameren Companies:
| | 2006 | | 2005 | |
Ameren:(a) | | | | | | |
| Net income | $ | 70 | | $ | 121 | |
| Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(10) and $15, respectively | | (15 | ) | | 17 | |
| Reclassification adjustments for (gains) included in net income, net of taxes of $3 and $-, respectively | | (5 | ) | | - | |
Total comprehensive income, net of taxes | $ | 50 | | $ | 138 | |
UE: | | | | | | |
Net income | $ | 51 | | $ | 57 | |
| Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(1) and $2, respectively | | (2 | ) | | 3 | |
Reclassification adjustments for (gains) included in net income, net of taxes of $1 and $-, respectively | | (1 | ) | | - | |
Total comprehensive income, net of taxes | $ | 48 | | $ | 60 | |
CIPS: | | | | | | |
Net income (loss) | $ | (1 | ) | $ | 8 | |
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(2) and $3, respectively | | (2 | ) | | 6 | |
Reclassification adjustments for (gains) included in net income, net of taxes of $1 and $ -, respectively | | (2 | ) | | - | |
Total comprehensive income, net of taxes | $ | (5 | ) | $ | 14 | |
| | | | | | | |
| | | 2006 | | | 2005 | |
Genco: | | | | | | |
Net income | $ | 6 | | $ | 31 | |
| Unrealized (loss) on derivative hedging instruments, net of taxes of $- and $ -, respectively | | - | | | (1 | ) |
| Reclassification adjustments for losses included in net income, net of taxes of $- and $-, respectively | | 1 | | | - | |
Total comprehensive income, net of taxes | $ | 7 | | $ | 30 | |
CILCORP: | | | | | | |
Net income | $ | 8 | | $ | 9 | |
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(5) and $8, respectively | | (7 | ) | | 15 | |
| Reclassification adjustments for (gains) included in net income, net of taxes of $3 and $-, respectively | | (4 | ) | | - | |
Total comprehensive income, net of taxes | $ | (3 | ) | $ | 24 | |
CILCO: | | | | | | |
Net income | $ | 17 | | $ | 16 | |
| Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(5) and $8, respectively | | (7 | ) | | 13 | |
Reclassification adjustments for (gains) included in net income, net of taxes of $3 and $-, respectively | | (4 | ) | | - | |
Total comprehensive income, net of taxes | $ | 6 | | $ | 29 | |
IP: | | | | | | |
Net income | $ | 4 | | $ | 22 | |
Unrealized (loss) on derivative hedging instruments, net of taxes (benefit) of $(1) and $ -, respectively | | (1 | ) | | - | |
Reclassification adjustments for losses included in net income, net of taxes (benefit) of $(1) and $-, respectively | | 1 | | | - | |
Total comprehensive income, net of taxes | $ | 4 | | $ | 22 | |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
NOTE 11 - 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, 2005, and assuming continuation of the recently expired federal interest rate relief beyond 2006, in order to maintain minimum funding levels for Ameren’s pension plans, we do not expect future contributions to be required until 2011 at which time we would expect a required contribution of $100 million to $150 million. If federal interest rate relief is not continued in its most recent form, $200 million to $300 million may need to be funded in 2009 to 2010 based on other recent federal legislative proposals. These amounts are estimates. They may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions.
The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit plans for the three months ended March 31, 2006 and 2005:
| | Pension Benefits(a) | | Postretirement Benefits(a) | |
| | 2006 | | 2005 | | 2006 | | 2005 | |
| Service cost | $ | 16 | | $ | 15 | | $ | 6 | | $ | 6 | |
| Interest cost | | 43 | | | 42 | | | 18 | | | 19 | |
| Expected return on plan assets | | (49 | ) | | (46 | ) | | (12 | ) | | (12 | ) |
| Amortization of: | | | | | | | | | | | | |
Prior service cost | | 2 | | | 2 | | | (1 | ) | | (1 | ) |
Actuarial loss | | 11 | | | 10 | | | 10 | | | 10 | |
| Net periodic benefit cost | $ | 23 | | $ | 23 | | $ | 21 | | $ | 22 | |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
UE, CIPS, Genco, CILCORP, CILCO and IP are participants in Ameren’s plans and are responsible for their proportional share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three months ended March 31, 2006 and 2005:
| | Pension Costs | | Postretirement Costs | |
| | | 2006 | | | 2005 | | | 2006 | | | 2005 | |
| UE | $ | 13 | | $ | 13 | | $ | 11 | | $ | 11 | |
| CIPS | | 3 | | | 3 | | | 3 | | | 3 | |
| Genco | | 2 | | | 2 | | | 1 | | | 1 | |
| CILCORP | | 2 | | | 3 | | | 3 | | | 4 | |
| CILCO | | 3 | | | 4 | | | 5 | | | 6 | |
| IP | | 2 | | | 2 | | | 4 | | | 3 | |
NOTE 12 - SEGMENT INFORMATION
Ameren’s reportable segment Utility Operations comprises its electric generation and electric and gas transmission and distribution operations. It includes the operations of UE, CIPS, Genco, CILCORP, CILCO and IP. Ameren’s reportable segment Other consists of the parent holding company, Ameren Corporation.
The accounting policies for segment data are the same as those described in Note 1 - Summary of Significant Accounting Policies. Segment data includes intersegment revenues, as well as a charge for allocating costs of administrative support services to each of the operating companies, which in each case is eliminated upon consolidation. Ameren Services allocates administrative support services based on various factors, such as head count, number of customers, and total assets.
The following table presents information about the reported revenues and net income of Ameren for the three months ended March 31, 2006 and 2005:
| | Utility Operations | | Other | | Reconciling Items(a) | | Total | |
2006: | | | | | | | | | | | | |
| Operating revenues | $ | 2,252 | | $ | - | | $ | (452 | ) | $ | 1,800 | |
| Net income | | 71 | | | (1 | ) | | - | | | 70 | |
2005: | | | | | | | | | | | | |
| Operating revenues | $ | 1,944 | | $ | - | | $ | (318 | ) | $ | 1,626 | |
| Net income | | 125 | | | (4 | ) | | - | | | 121 | |
| (a) | Elimination of intercompany revenues. |
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
OVERVIEW
Ameren Executive Summary
Despite solid operations, Ameren’s first quarter 2006 earnings fell short of the strong earnings achieved last year. Several factors negatively impacted Ameren’s earnings. Temperatures during the 2006 winter season in Ameren’s service territory were extremely mild resulting in lower electric and gas margins. Electric margins were also negatively impacted by higher fuel and purchased power costs due primarily to increased coal and related transportation costs. In addition, Ameren incurred incremental costs of operating in the MISO Day Two Energy Market in the first quarter of 2006 because MISO Day Two operations did not commence until the second quarter last year. These factors offset higher margins from organic growth and interchange sales compared to the first quarter of last year. Other operating expenses and taxes other than income taxes also rose, negatively affecting earnings for the quarter. These expenses rose primarily as a result of higher gross receipts taxes, the absence of a favorable property tax settlement, such as the one realized during the first quarter of 2005, and higher bad debt expenses.
Ameren continues to have quite a bit of activity on the regulatory front. In delivery services rate filings made in late December 2005, CIPS, CILCO and IP requested a total combined annual electric revenue increase of approximately $200 million. In April 2006, the ICC staff, the Illinois attorney general and CUB recommended combined annual electric revenue increases in the range of $70 million. The ICC has until November of this year to issue a final decision in these cases. As a result of the potential increases to ratepayers from this increase request and the transition to market-based power costs, there have been two pieces of legislation proposed in Illinois. One proposal includes a potential extension of the rate freeze through 2010, which we believe is without legal merit. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power costs from their electric customers in a timely manner could result in material adverse consequences for these companies. Following the introduction of the rate freeze proposal, a second separate and constructive piece of legislation was introduced, which would authorize the issuance of securitization bonds that would effectively result in the deferral for up to 10 years of power procurement costs for residential customers. This proposed legislation would result in recovery of the deferred power procurement costs immediately upon the issuance of securitization bonds. In Missouri, UE expects to file for a rate increase later this year. The exact timing of the filing, and amount of the requested increase, is still to be determined. The MoPSC staff and others will review any filing and, based upon their analyses, will make their own rate recommendations.
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren was registered with the SEC as a public utility holding company under PUHCA 1935, until that act was repealed effective February 8, 2006. Ameren’s primary asset is the common stock of its subsidiaries. Ameren’s subsidiaries, which are separate, independent legal entities with separate businesses, assets and liabilities, 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 depend 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 our 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. Before May 2, 2005, UE also operated those businesses 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, a subsidiary of CILCORP (a holding company), 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. |
In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information helps readers to understand the impact of these factors on Ameren’s earnings per share. All references in this report to earnings per share are based on weighted-average diluted common shares outstanding during the applicable period. All tabular dollar amounts are in millions, unless otherwise indicated.
RESULTS OF OPERATIONS
Earnings Summary
Our results of operations and financial position are affected by many factors. Weather, economic conditions, and the actions of key customers or competitors can significantly affect the demand for our services. Our results are also affected by seasonal fluctuations: winter heating and summer cooling demands. Approximately 85% of Ameren’s 2005 revenues were directly subject to state and federal regulation. This regulation can have a material impact on the price 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 global economic and political environment, weather, supply and demand, 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 in each state for our gas delivery businesses. The electric and gas rates for UE in Missouri are set through June 2006 and for CIPS, CILCO and IP in Illinois through January 1, 2007; therefore, cost decreases or increases will not be immediately reflected in rates. Fluctuations in interest rates affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risks and other risks inherent in our businesses. The reliability of our power plants and transmission and distribution systems, the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.
Ameren’s net income decreased to $70 million, or 34 cents per share, in the first quarter of 2006 from $121 million, or 62 cents per share, in the first quarter of 2005. This decrease in net income was due to a combination of factors in the first quarter of the current year, including extremely mild winter weather conditions, higher fuel prices and transportation costs, the unavailability of UE’s Taum Sauk plant due to an upper reservoir breach, increased purchased power costs as a result of higher power prices and incremental costs of operating in the MISO Day Two Energy Market, and increased other operating expenses. An increase in the number of common shares outstanding also reduced Ameren’s earnings per share in the first quarter of 2006 compared with the first quarter of 2005. Increased margins on interchange sales from EEI and organic growth in revenues reduced the impact of these items on first quarter 2006 earnings.
Because it is 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 ended March 31, 2006 and 2005:
| | 2006 | | 2005 | |
| Net income (loss): | | | | | | |
UE(a) | $ | 50 | | $ | 56 | |
| CIPS | | (2 | ) | | 7 | |
Genco(a) | | 6 | | | 31 | |
CILCORP(a) | | 8 | | | 9 | |
| IP | | 3 | | | 21 | |
Other(b) | | 5 | | | (3 | ) |
| Ameren net income | $ | 70 | | $ | 121 | |
| (a) | Includes earnings from market-based interchange power sales that provided the following contributions to net income: |
UE: 2006 - $20 million; 2005 - $22 million.
Genco: 2006 - $7 million; 2005 - $12 million.
CILCORP: 2006 - $7 million; 2005 - $5 million.
| (b) | Includes earnings from EEI, corporate general and administrative expenses, other non-rate-regulated operations, and intercompany eliminations. |
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 ended March 31, 2006, as compared with the year-ago period. 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 the financial information we provide 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 provide elsewhere in this report.
Three Months | Ameren(a) | | UE | | CIPS | | Genco | | CILCORP | | CILCO | | IP | |
| Electric revenue change: | | | | | | | | | | | | | | | | | | | | | |
| Effect of weather (estimate) | $ | (11 | ) | $ | (5 | ) | $ | (5 | ) | $ | - | | $ | (1 | ) | $ | (1 | ) | $ | - | |
| Growth and other (estimate) | | 14 | | | (2 | ) | | 45 | | | 15 | | | 5 | | | 5 | | | 7 | |
| Interchange revenues | | 79 | | | 41 | | | (8 | ) | | 7 | | | (5 | ) | | (5 | ) | | - | |
| Total | $ | 82 | | $ | 34 | | $ | 32 | | $ | 22 | | $ | (1 | ) | $ | (1 | ) | $ | 7 | |
| Fuel and purchased power change: | | | | | | | | | | | | | | | | | | | | | |
| Fuel: | | | | | | | | | | | | | | | | | | | | | |
Generation and other | $ | (15 | ) | $ | (3 | ) | $ | - | | $ | (9 | ) | $ | - | | $ | (1 | ) | $ | - | |
Price | | (26 | ) | | (16 | ) | | - | | | (10 | ) | | - | | | - | | | - | |
Purchased power | | (68 | ) | | (29 | ) | | (31 | ) | | (47 | ) | | 7 | | | 7 | | | (20 | ) |
| Total | $ | (109 | ) | $ | (48 | ) | $ | (31 | ) | $ | (66 | ) | $ | 7 | | $ | 6 | | $ | (20 | ) |
| Net change in electric margins | $ | (27 | ) | $ | (14 | ) | $ | 1 | | $ | (44 | ) | $ | 6 | | $ | 5 | | $ | (13 | ) |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
Ameren
Ameren’s electric margin decreased $27 million, or 4%, for the three months ended March 31, 2006, compared with the same period in 2005. Ameren’s electric rates charged to its UE, CIPS, CILCO and IP regulated customers were unchanged in 2006 from 2005 levels. The decrease in electric margin was due to increased fuel and purchased power costs. Increases in margins on interchange sales, primarily from EEI, reduced the impact of these increased costs.
As discussed above, Ameren’s electric margin decreased because of a $109 million, or 26%, increase in fuel and purchased power costs for the three months ended March 31, 2006, compared with the same period in 2005. Fuel and purchased power costs increased primarily because of increased coal and transportation prices, MISO Day Two Energy Market costs, and increased emission allowance utilization at Genco and AERG. Costs related to the MISO Day Two Energy Market, which commenced operations in April 2005, totaled $26 million for the three months ended
March 31, 2006, versus none in the prior-year period. In the first quarter of 2006, UE incurred $6 million in incremental fees levied by FERC upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant. Finally, the unavailability of UE’s Taum Sauk hydroelectric plant resulted in an estimated $6 million increase in fuel and purchased power costs for the three months ended March 31, 2006, compared with the same period in 2005.
The decrease in electric margins was reduced by a $49 million, or 73%, increase in margins on interchange sales for the first three months of 2006, compared with the same period in 2005. Interchange margins increased primarily because of the increased sale of power from EEI resulting from the expiration of affiliate cost-based sales contracts on December 31, 2005, and because of higher average power prices. In addition, there was increased availability of low-cost generation resulting from reduced demand from native load customers due to the mild weather as well as improved power plant availability. Average realized power prices on interchange sales increased to approximately $47 per megawatthour in the first three months of 2006 from approximately $38 per megawatthour in the comparable period of 2005. Average power prices increased because of slightly higher market prices and increased on-peak sales from EEI. Reduced transmission losses as a result of entering the MISO Day Two Energy Market also contributed to an estimated $6 million increase in margins on interchange sales in the first three months of 2006 as compared to the year-ago period. Ameren’s baseload electric generating plants’ average capacity factor was approximately 80% in the first quarter of 2006 compared with 76% in the same period of 2005 and the equivalent availability factor was approximately 90%, as compared with 84% in the prior-year period.
UE
UE’s electric margin decreased $14 million, or 4%, for the first three months of 2006, compared to the same period in 2005. The decrease in margin was due to increased fuel and purchased power costs. In addition, the transfer of UE’s Illinois service territory to CIPS on May 2, 2005, resulted in lost margins totaling $18 million and contributed to UE’s decrease in electric margin for the first three months of 2006 compared to the same period in 2005. Partially offsetting these decreases to margin were sales to Noranda, which became a significant new industrial customer on June 1, 2005, and an increase in margins on interchange sales. The addition of Noranda added approximately $6 million in electric margin in the first three months of 2006.
Fuel and purchased power costs increased $48 million, or 33%, for the first three months of 2006 compared to the same period in 2005 primarily because of higher coal and transportation costs. Several other factors contributed to higher fuel and purchased power costs as well. In the first quarter of 2006, UE incurred $6 million in incremental fees levied by FERC upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant. In addition, UE had to supply higher-cost power to its native load customers as a cost-based power supply contract with EEI expired on December 31, 2005. MISO Day Two Energy Market costs, totaling $16 million, in the first three months of 2006 were also a contributing factor to UE’s increased purchased power costs over the first quarter of 2005.
UE’s margins on interchange sales increased for the first three months of 2006, compared with the same period in 2005. Margins on interchange sales to affiliates increased because of the amendment of the joint dispatch agreement between UE and Genco and increased sales to Genco to serve a greater load primarily resulting from the transfer of UE’s Illinois service territory to CIPS. The joint dispatch agreement determines the allocation of margins or profits from short-term sales of excess generation to third parties between UE and Genco. The MoPSC-required, and FERC-approved, change in the methodology to base the allocation on generation output instead of load requirements, effective January 10, 2006, resulted in $9 million in incremental margins on interchange sales for UE in the first quarter of 2006 as compared to the year-ago period. In addition, margins on interchange sales with non-affiliates increased $3 million in the first three months of 2006, compared with the same period in 2005, primarily because of higher power prices and access to the MISO Day Two Energy Market. Reduced transmission losses as a result of entering the MISO Day Two Energy Market resulted in $4 million in increased margins on interchange sales.
CIPS
CIPS’ electric margin increased $1 million, or 2%, for the first three months of 2006, compared to the same period in 2005, primarily because of increased industrial sales as a result of the transfer to CIPS of UE’s Illinois service territory on May 2, 2005, and customers switching back to CIPS from Marketing Company because tariff rates were below market rates for power. The transfer of UE’s Illinois service territory resulted in a $12 million increase in electric margin in the first quarter of 2006 over the prior-year period. Revenues declined $5 million in the first three months of 2006, compared to the same period last year because of milder weather, resulting in a decrease in electric margin of $3 million from the prior-year period as incremental energy costs under the power supply agreement with Marketing Company were similar to the previous-year period. Increased MISO Day Two Energy Market costs, totaling approximately $4 million, also reduced electric margins. Due to the expiration of the CIPS’ power supply agreement with EEI in December 2005, where CIPS sold its entitlements under the agreement with EEI to
Marketing Company, both interchange revenues and purchased power expenses decreased $8 million.
Genco
Genco’s electric margin decreased $44 million, or 35%, in the first three months of 2006, compared with the same period in 2005, primarily because of lower wholesale margins, higher coal and transportation prices, increased purchased power costs, higher emission allowance utilization costs, and incremental MISO Day Two Energy Market expenses. In addition, power prices under Genco’s principal power supply contract for CIPS (through Marketing Company) remained unchanged. Wholesale margins decreased because Genco purchased higher-cost power from affiliates and third parties to serve a greater load. Emission allowance utilization increased fuel costs by $4 million in 2006. The first quarter 2006 MISO Day Two Energy Market costs totaling $4 million versus none in the prior-year period were also a contributing factor to Genco’s increased purchased power costs. Power costs averaged $26 per megawatthour in the first three months of 2006 compared to approximately $14 per megawatthour in the year-ago period. The increase in revenues due to the transfer of UE’s Illinois service territory to CIPS in May 2005 was partially offset by lower wholesale sales as a result of the expiration of several large contracts in 2005.
Genco’s margin on interchange sales decreased in the first three months of 2006, compared with the same period in 2005, primarily because a $9 million reduction due to the amendment of the joint dispatch agreement between UE and Genco discussed above. The impact of this change was reduced by the benefit of higher power prices and access to the MISO Day Two Energy Market.
CILCORP and CILCO
Electric margin increased $6 million, or 10%, and $5 million, or 8%, at CILCORP and CILCO, respectively, in the first three months of 2006 compared with the same period in 2005 primarily because of lower purchased power costs and higher margins on interchange sales. Purchased power costs decreased because of improved plant availability. No planned outages occurred in the first three months of 2006, compared with a planned outage that occurred at one of AERG’s power plants in the same period in 2005. Margins on interchange sales increased $3 million. Reducing the increase in electric margins at CILCORP and CILCO was MISO Day Two Energy Market costs totaling $1 million in the first three months of 2006 compared with none in the same period in 2005.
IP
IP’s electric margin decreased $13 million, or 17%, in the first three months of 2006, compared to the same period in 2005, primarily because of higher purchased power costs. Purchased power costs were $20 million higher due to increased power prices as a result of the expiration of its cost-based power supply agreement with EEI on December 31, 2005, and a 12% increase in average purchased power cost per megawatthour.
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 ended March 31, 2006, compared with the year-ago period. We consider gas margin to be a useful measure of the change in profitability of our gas utility operations between periods. The table below complements the financial information we provide in accordance with GAAP. However, gas margin may not be a presentation defined under GAAP. Our presentation may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.
| | Three Months | |
Ameren(a) | $ | (6 | ) |
| UE | | (5 | ) |
| CIPS | | - | |
| CILCORP | | (3 | ) |
| CILCO | | (3 | ) |
| IP | | 3 | |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
Ameren
Ameren’s gas margin decreased by $6 million, or 4%, for the three months ended March 31, 2006, over the same period in 2005 primarily because of extremely mild weather conditions that reduced gas margins as heating degree-days were about 11% below a mild 2005 first quarter. Residential and commercial gas volume sales, which are correlated to heating degree-days, both decreased 12%, for the three months ended March 31, 2006, compared with the same period in 2005. Ameren’s decrease in gas margin in the first quarter of 2006 was reduced by, among other things, the effect of an IP rate increase effective in May 2005 that added revenues of $4 million. Other delivery services rates were flat between periods.
UE
UE’s gas margin decreased by $5 million, or 17%, for the three months ended March 31, 2006, compared with the same period in 2005, primarily because of the transfer of UE’s Illinois service territory to CIPS, which reduced gas margins by $3 million, and extremely mild weather conditions, as evidenced by an 8% decrease in heating degree-days in UE’s service territory. Residential and commercial gas sales decreased 22% and 18%, respectively, for the three months
ended March 31, 2006, compared with the same period in 2005 primarily as a result of the extremely mild weather and the transfer of UE’s Illinois service territory to CIPS. Industrial gas sales also decreased 30% over the same period primarily because of the UE Illinois service territory transfer to CIPS.
CIPS
CIPS’ gas margin for the three months ended March 31, 2006, was comparable with the same period in 2005. The transfer to CIPS of UE’s Illinois service territory increased gas margin by $3 million and industrial gas sales by 25%. The increase in gas margin was offset by extremely mild weather as evidenced by a 15% decrease in heating degree-days.
CILCORP and CILCO
CILCORP’s and CILCO’s gas margins each decreased by $3 million, or 9%, for the three months ended March 31, 2006, over the same period in 2005, primarily as a result of extremely mild weather conditions as heating degree-days were 9% below the first quarter of 2005 in CILCO’s service territory. This resulted in a 13% decrease in both residential and commercial gas sales.
IP
IP’s gas margin increased $3 million, or 6%, for the three months ended March 31, 2006, over the same period in 2005, primarily because of a rate increase effective in May 2005 that added revenues of $4 million. This increase was reduced by extremely mild weather conditions as evidenced by a 12% decrease in heating degree-days in 2006 as compared with the year-ago period in IP’s service territory. Residential and commercial gas sales decreased 12% and 15%, respectively, for the three months ended March 31, 2006, compared with the same period in 2005.
Operating Expenses and Other Statement of Income Items
Other Operations and Maintenance
Ameren
Ameren’s other operations and maintenance expenses increased $3 million in the first three months of 2006, as compared with the same period in 2005, primarily because of higher bad debt expense. Bad debt expense increased as a result of actions by the Illinois governor to restrict customer disconnections during the first quarter of 2006 and higher gas billings resulting from increased gas prices.
UE
Other operations and maintenance expenses at UE decreased $10 million in the first quarter of 2006 as compared with the first quarter of 2005. The transfer of UE’s Illinois service territory to CIPS in May 2005 resulted in a decrease in other operations and maintenance expenses at UE in the first quarter of the current year of $6 million as compared to the same period in 2005. A reduction in injuries and damages expenses also contributed to the favorable variance.
CIPS
Other operations and maintenance expenses at CIPS increased $5 million in the first three months of 2006, as compared with the first three months of 2005, primarily because of the transfer of UE’s Illinois service territory to CIPS in May 2005, which resulted in an increase in other operations and maintenance expenses of $6 million at CIPS in the current year period as compared to the same period in 2005.
Genco
Genco’s other operations and maintenance expenses decreased $6 million in the first three months of 2006, as compared with the first three months of 2005, primarily because of lower maintenance expenses due to a major power plant outage in the first quarter of 2005.
CILCORP
Other operations and maintenance expenses at CILCORP were comparable for the three months ended March 31, 2006, with the same period in 2005.
CILCO
CILCO’s other operations and maintenance expenses decreased $3 million in the first quarter of 2006 from the same period in 2005 primarily because of lower employee benefit costs, partially offset by increased bad debt expense.
IP
IP’s other operations and maintenance expenses increased $17 million in the first quarter of 2006 over the same period in 2005 primarily because of higher labor costs and increased information technology and bad debt expenses.
Depreciation and Amortization
Variations in depreciation and amortization expenses at the Ameren Companies between the first quarter of 2006 and the first quarter of 2005 were as follows:
Ameren - Increased $8 million as a result of capital additions, primarily at UE, and the impairment of an intangible asset associated with the CILCORP acquisition.
UE - Increased $4 million primarily because of capital additions, a portion of which were related to new steam generators and turbine rotors installed during the refueling and maintenance outage at the Callaway nuclear plant in the prior year. Partially offsetting these increases was a reduction of depreciation due to the transfer of property to CIPS in the Illinois service territory transfer.
CIPS - Increased $3 million primarily because of depreciation on property transferred to CIPS from UE Illinois service territory transfer along with capital additions.
CILCORP - Increased $4 million due to the impairment of an intangible asset established in conjunction with Ameren’s acquisition of CILCORP.
Genco, CILCO and IP - Depreciation and amortization expenses were comparable between periods.
Taxes Other Than Income Taxes
Variations in taxes other than income taxes at the Ameren Companies between the first three months of 2006 and the first three months of 2005 were as follows:
Ameren - Increased $22 million primarily as a result of higher gross receipts taxes and higher property taxes at Genco.
UE - Increased $4 million primarily as a result of higher gross receipts taxes.
CIPS - Increased $4 million primarily as a result of higher gross receipts and excise taxes.
Genco - Increased $8 million because of higher property taxes due to the absence in 2006 of an $8 million tax settlement that was received in the first quarter of 2005.
CILCORP, CILCO and IP - Taxes other than income taxes were comparable between periods.
Other Income and Expenses
Variations in other income and expenses at the Ameren Companies between the first quarter of 2006 and the first quarter of 2005 were as follows:
Ameren and UE - Income decreased $3 million and $4 million at Ameren and UE, respectively, primarily as a result of a lower capitalization of funds used during construction.
CIPS, Genco, CILCORP, CILCO and IP - Other income and expenses were comparable between periods.
Interest
Variations in interest expense at the Ameren Companies between the first three months of 2006 and the first three months of 2005 were as follows:
Ameren, CIPS, CILCORP, CILCO and IP - Interest expense was comparable between periods. At Ameren, increased interest expense from the issuance of senior secured notes in 2005 at UE was offset by a decrease in interest expense resulting from the repurchase and retirement of Ameren’s $95 million of senior notes in February 2005 and the maturity of Genco’s senior notes in November 2005.
UE - Increased $10 million primarily because of the issuances of $300 million of senior secured notes in July 2005 and $260 million of senior secured notes in December 2005.
Genco - Decreased $6 million primarily because of the maturity of $225 million of senior notes in November 2005, lower average money pool borrowings, and a reduction in principal amounts outstanding on intercompany promissory notes to CIPS and Ameren. The intercompany note payable to Ameren was repaid in May 2005.
Income Taxes
Income tax expense at Ameren, UE, CIPS, Genco and IP decreased primarily because of lower pretax income. Income tax expense at CILCORP and CILCO was comparable for the first three months of 2006 compared with the same period in 2005.
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 Ameren. For operating cash flows, 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 short and long-term contracts. Commencing in 2007, Genco intends to sell power previously sold under these contracts through
the proposed auctions for CIPS, CILCO and IP and to other wholesale and retail customers. In addition, each of the Ameren Companies plans to use short-term borrowings to support normal operations and other temporary capital requirements. The use of operating cash flows and short-term borrowings to fund capital expenditures and other investments may periodically result in a working capital deficit, as was the case at March 31, 2006, for Ameren, UE, Genco, CILCORP, CILCO and IP. Ameren will discretionarily reduce its short-term borrowings with cash from operations or with long-term borrowings.
The following table presents net cash provided by (used in) operating, investing and financing activities for the three months ended March 31, 2006 and 2005:
| | Net Cash Provided By Operating Activities | | Net Cash Provided By (Used In) Investing Activities | | Net Cash Provided By (Used In) Financing Activities | |
| | 2006 | | 2005 | | Variance | | 2006 | | 2005 | | Variance | | 2006 | | 2005 | | Variance | |
Ameren(a) | $ | 287 | | $ | 357 | | $ | (70 | ) | $ | (494 | ) | $ | (202 | ) | $ | (292 | ) | $ | 140 | | $ | (194 | ) | $ | 334 | |
| UE | | 60 | | | 107 | | | (47 | ) | | (403 | ) | | (185 | ) | | (218 | ) | | 324 | | | 32 | | | 292 | |
| CIPS | | 67 | | | 66 | | | 1 | | | (64 | ) | | (10 | ) | | (54 | ) | | (3 | ) | | (56 | ) | | 53 | |
| Genco | | 40 | | | 38 | | | 2 | | | (10 | ) | | (24 | ) | | 14 | | | (30 | ) | | (15 | ) | | (15 | ) |
| CILCORP | | 61 | | | 41 | | | 20 | | | (19 | ) | | (13 | ) | | (6 | ) | | (42 | ) | | (31 | ) | | (11 | ) |
| CILCO | | 61 | | | 45 | | | 16 | | | (19 | ) | | (19 | ) | | - | | | (43 | ) | | (27 | ) | | (16 | ) |
| IP | | 64 | | | 113 | | | (49 | ) | | (37 | ) | | 1 | | | (38 | ) | | (26 | ) | | (114 | ) | | 88 | |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
Cash Flows from Operating Activities
Ameren’s cash from operations decreased in 2006, as compared with 2005, due primarily to decreases in electric and gas margins as discussed in Results of Operations above. Also contributing to the decrease was cash used during the first quarter of 2006 for payment of 2005 year-end accruals including real estate and property taxes, annual incentive compensation that was more than it was a year ago due to increased 2005 earnings relative to performance targets, and trade payables that were higher than normal due to an unusually cold December 2005 and higher natural gas prices. Reducing this negative impact was the collection of higher-than-normal trade receivables caused by cold December weather, and the sale of gas inventories during the winter heating season. The cash impact from trade receivables and inventory reductions was more significant in the current period due to higher gas prices than the year-ago period.
At UE, cash from operating activities decreased in 2006 due to lower electric and gas margins and cash used for working capital changes that primarily included increased payments of year-end accruals in the first quarter of 2006 as compared with the year-ago period as discussed above for Ameren.
At CIPS, the negative cash effect of higher other operations and maintenance expenses and taxes other than income, as discussed in Results of Operations, was offset by a cash benefit from reduced working capital investment, resulting in operating cash flow in the first quarter of 2006 that was consistent with the 2005 period. The most significant working capital cash benefit was the reduction of trade receivables that was greater than the year-ago period as a result of colder December weather and higher gas prices compared to the year-ago period. The acquisition of UE’s Illinois service territory in May 2005 also increased receivables and payables.
Genco’s cash from operating activities in the first quarter of 2006 was comparable to the 2005 period primarily because the negative cash effect of lower operating margins was partially offset by an $18 million reduction in emission allowance purchases and lower interest payments as a result of decreased debt outstanding.
Cash from operating activities increased for CILCORP and CILCO in the first quarter of 2006 compared with the 2005 period primarily because of a $9 million decrease in emission allowance purchases in 2006 as compared with the year-ago period. In addition, gas inventories were reduced as a result of sales during the winter heating season creating a cash benefit. As discussed above, the period-over-period impact was greater in 2006 due to higher natural gas prices.
IP’s cash from operations decreased in the first quarter of 2006 compared with the 2005 period due to lower electric margins and higher other operations and maintenance expenses as discussed above in Results of Operations. Also contributing to IP’s decreased operating cash flows in 2006 were income taxes paid of $16 million in the 2006 period as compared with income tax refunds of $10 million in the year-ago period. The 2005 period included more tax benefits from Ameren’s acquisition of IP and tax benefits from premiums paid for early debt redemptions made in 2004.
Cash Flows from Investing Activities
Ameren’s increase in cash used in investing activities was primarily because of UE’s purchases of a 640-megawatt CT facility from affiliates of NRG, and 510-megawatt and 340-megawatt CT facilities from subsidiaries of Aquila, Inc. for $292 million. The CT purchases are intended to meet UE’s
increased generating capacity needs and provide UE with additional flexibility in determining future base-load generating capacity additions.
Excluding the CT purchases, Ameren’s and UE’s capital expenditures decreased $31 million and $29 million, respectively, in the first quarter of 2006 as compared with the year-ago period primarily because fewer capital resources were allocated to other projects due to the planned CT acquisitions.
CIPS’ increase in cash used in investing activities in the first quarter of 2006 over the 2005 period was due to a $7 million increase in capital expenditures and $47 million of advances to the money pool in 2006. The increased capital expenditures resulted partly from CIPS’ expansion of its service territory because of its acquisition of UE’s Illinois utility operations in May 2005. CIPS’ capital expenditures were for projects to improve the reliability of its electric and gas transmission and distribution systems.
Genco’s capital expenditures were lower in the first quarter of 2006 compared with the 2005 period because 2005 included more expenditures due to an extended planned outage at one of its power plants in 2005.
CILCORP’s and CILCO’s cash used in investing activities were comparable in the first quarters of the 2006 and 2005 periods, except for the absence in 2006 of CILCORP’s cash from repayments in 2005 of prior period advances to the money pool.
IP’s cash from investing activities in 2006 decreased primarily because of the absence in the first quarter of 2006 of proceeds received in the first quarter of 2005 from repayments received for advances made to the money pool in prior periods.
See Note 8 - Commitments and Contingencies and Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a further discussion of environmental matters and the UE CT acquisitions, respectively.
We continually review our generation portfolio and expected power needs. As a result, we could modify our plans 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.
Cash Flows from Financing Activities
Cash from financing activities increased for Ameren in 2006 from the year-ago period, primarily because of an increase in net short-term debt proceeds of $270 million, principally at UE, that were used to partially fund UE’s CT acquisitions. Decreased long-term debt redemptions of $158 million also contributed to the increase in cash from financing activities in 2006. These cash benefits were partially offset by an $85 million decrease in proceeds from long-term debt issuances.
UE’s cash from financing activities increased in the first quarter of 2006, as compared with the 2005 period, primarily because of a $356 million increase in short-term debt proceeds related to the CT acquisitions and an $18 million decrease in dividend payments. These increases were reduced by an $85 million decrease in long-term debt proceeds.
CIPS’ cash used in financing activities decreased in the first quarter of 2006, as compared with the 2005 period, because of a $53 million decrease in payments to the money pool in the 2006 period.
Genco’s cash used in financing activities increased in the first quarter of 2006 from the same period in 2005 primarily because of increased money pool payments and common stock dividend payments of $7 million and $8 million, respectively.
CILCORP’s and CILCO’s cash used in financing activities increased primarily due to increases in common stock dividends of $20 million and $30 million, respectively, that were partially offset by net increases in cash from money pool borrowings of $11 million and $13 million at CILCORP and CILCO, respectively.
IP’s cash used in financing activities decreased in the first quarter of 2006, as compared with the 2005 period, primarily because of lower redemptions and repurchases of long-term debt of $69 million and the absence in 2006 of a $20 million common stock dividend payment made in 2005.
Short-term Borrowings and Liquidity
For information on credit facilities, 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 3 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report.
The following table presents the committed bank credit facilities of Ameren and EEI as of March 31, 2006:
Credit Facility | Expiration | | Amount Committed | | Amount Available | |
Ameren:(a) | | | | | | |
Multiyear revolving(b) | July 2010 | | $ | 1,150 | | $ | 686 |
Multiyear revolving | July 2010 | | | 350 | | | 350 |
EEI: | | | | | | | |
Bank credit facility(c) | April 2006 | | | 20 | | | 20 |
Total | | | $ | 1,520 | | $ | 1,056 |
| (a) | Ameren Companies may access these credit facilities through intercompany borrowing arrangements. |
| (b) | UE, CIPS, Genco, CILCO and IP are also direct borrowers under this agreement. |
| (c) | This facility expired in April 2006 and was not renewed. |
In addition to committed credit facilities, a further source of liquidity for Ameren from time to time is available cash and cash equivalents. At March 31, 2006, Ameren had $29 million of cash and cash equivalents.
With the repeal of PUHCA 1935 in February 2006, the issuance of short-term debt securities by Ameren’s utility subsidiaries is now subject to approval by FERC under the Federal Power Act. In March 2006, FERC issued an order authorizing these subsidiaries to issue short-term debt securities subject to the following limits on outstanding balances:
UE - $1 billion; CIPS - $250 million; and CILCO - $250 million. This authorization is effective as of April 1, 2006, and terminates on March 31, 2008.
Genco is also authorized by FERC in its March 2006 order to have up to $300 million of short-term debt outstanding at any time. IP and EEI have unlimited short-term debt authorization from FERC.
With the repeal of PUHCA 1935 in February 2006, the issuance of short-term debt securities by Ameren and CILCORP, which was previously subject to SEC approval under PUHCA 1935, is no longer subject to approval by any regulatory body.
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 (net of any issuance discounts and including any redemption premiums) for the three months ended March 31, 2006 and 2005, for the Ameren Companies. For additional information, see Note 4 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report.
| | | | Three Months |
| | Month Issued, Redeemed, Repurchased or Matured | | 2006 | | 2005 |
Issuances | | | | | | | | |
Long-term debt | | | | | | | | |
UE: | | | | | | | | |
5.00% Senior secured notes due 2020 | January | | $ | - | | $ | 85 | |
Total Ameren long-term debt issuances | | | $ | - | | $ | 85 | |
Common stock | | | | | | | | |
Ameren: | | | | | | | | |
DRPlus and 401(k) | Various | | $ | 27 | | $ | 30 | |
| Total common stock issuances | | | $ | 27 | | $ | 30 | |
| Total Ameren long-term debt and common stock issuances | | | $ | 27 | | $ | 115 | |
Redemptions, Repurchases and Maturities | | | | | | | | |
Long-term debt | | | | | | | | |
Ameren: | | | | | | | | |
Senior notes due 2007(a) | February | | $ | - | | $ | 95 | |
CILCORP: | | | | | | | | |
9.375% Senior notes due 2029 | March | | | 3 | | | - | |
IP: | | | | | | | | |
6.75% First mortgage bonds due 2005 | March | | | - | | | 70 | |
Note payable to IP SPT | | | | | | | | |
5.54% Series due 2007 | Various | | | 28 | | | - | |
5.38% Series due 2005 | Various | | | - | | | 22 | |
| Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities | | | $ | 31 | | $ | 187 | |
| (a) | Component of the adjustable conversion-rate equity security units. |
The following table presents the authorized amounts under Form S-3 shelf registration statements filed and declared effective for certain Ameren Companies as of March 31, 2006:
| | Effective Date | | Authorized Amount | | Issued | | Available | |
| Ameren | | June 2004 | | $ | 2,000 | | $ | 459 | | $ | 1,541 | |
| UE | | October 2005 | | | 1,000 | | | 260 | | | 740 | |
| CIPS | | May 2001 | | | 250 | | | 150 | | | 100 | |
Ameren also has approximately 4.6 million shares of common stock available for issuance under various other SEC effective registration statements applicable to its DRPlus and 401(k) plans as of March 31, 2006.
Ameren, UE and CIPS may sell all or a portion of the remaining securities registered under their effective registration statements if market conditions and capital requirements warrant such a sale. Any offer and sale will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.
Indebtedness Provisions and Other Covenants
See Note 3 - 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
Ameren’s bank credit facilities and applicable cross-default provisions. Also see Note 4 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report for a discussion of covenants and provisions contained in certain of the Ameren Companies’ indenture agreements and articles of incorporation.
At March 31, 2006, the Ameren Companies were in compliance with their credit agreement, indenture, and articles of incorporation provisions and covenants.
We consider access to short-term and long-term capital markets a significant source of funding for capital requirements not satisfied by our operating cash flows. Our inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing our current operating performance, liquidity, and credit ratings (see Credit Ratings below), we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets. Such events might increase our cost of capital or adversely affect our ability to access the capital markets.
Dividends
Dividends paid by Ameren to shareholders during the first three months of 2006 totaled $130 million, or 63.5 cents per share (2005 - $124 million or 63.5 cents per share). On May 2, 2006, Ameren’s board of directors declared a quarterly common stock dividend of 63.5 cents per share payable on June 30, 2006, to shareholders of record on June 7, 2006.
UE paid preferred stock dividends of approximately $1 million on February 15, 2006. CIPS paid preferred stock dividends of approximately $1 million on March 31, 2006. CILCO paid preferred stock dividends of less than $1 million on both January 3, 2006 and April 3, 2006. IP paid preferred stock dividends of approximately $1 million on both February 1, 2006 and May 1, 2006. The next preferred dividends are payable on May 15, 2006, June 30, 2006, July 3, 2006 and August 1, 2006 for UE, CIPS, CILCO and IP, respectively.
Certain of our financial agreements and articles of incorporation contain covenants and conditions that, among other things, would restrict the Ameren Companies’ payment of dividends in certain circumstances. At March 31, 2006, none of these circumstances existed and as a result, the Ameren Companies are allowed to pay dividends. In its approval of the acquisition of IP by Ameren, the ICC issued an order that permits 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% Series mortgage bonds. See Note 4 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report.
The following table presents dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents for the three months ended March 31, 2006 and 2005.
| | Three Months |
| | 2006 | | 2005 |
| UE | $ | 42 | | $ | 60 |
| Genco | | 22 | | | 14 |
CILCORP(a) | | 50 | | | 30 |
| IP | | - | | | 20 |
| Nonregistrants | | 16 | | | - |
| Dividends paid by Ameren | $ | 130 | | $ | 124 |
| (a) | CILCO paid dividends of $50 million and $20 million for the three months ended March 31, 2006 and 2005, respectively. |
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 Annual Report on Form 10-K for the fiscal year ended December 31, 2005. See Note 11 - Retirement Benefits to our financial statements under Part I, Item 1, of this report for information regarding expected minimum funding levels for our pension plan.
Subsequent to December 31, 2005, operating lease obligations increased at Ameren, UE, and Genco to $446 million, $207 million, and $169 million, respectively, as of March 31, 2006. Subsequent to December 31, 2005, obligations related to the procurement of coal and natural gas increased at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to
$4,203 million, $1,568 million, $498 million, $622 million, $660 million, $660 million and $564 million, respectively, as of March 31, 2006. Total other obligations at March 31, 2006, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $4,496 million, $1,717 million, $620 million, $622 million, $765 million, $765 million and $707 million, respectively.
Ameren’s and UE’s long-term debt increased $240 million as a result of the first quarter leasing transaction related to the Audrain CT acquisition as discussed in Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.
Credit Ratings
There have been no changes to the Ameren Companies’ credit ratings since the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005.
Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital. It may also increase the cost of borrowing and fuel and power supply, among other things, resulting in a negative impact on earnings. For example, if at March 31, 2006, the Ameren Companies had a sub-investment-grade rating (less than BBB- or Baa3), Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP could have been required to post collateral for certain trade obligations amounting to $119 million, $14 million, $7 million, $2 million, $16 million, $16 million, or $49 million, respectively. In addition, the cost of borrowing under our credit facilities can increase or decrease with credit ratings. A credit rating is not a recommendation to buy, sell or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.
OUTLOOK
Below are some key trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2006 and beyond:
Revenues
| · | By the end of 2006, electric rates for Ameren’s operating subsidiaries will have been fixed or declining for periods ranging from 15 years to 25 years. In 2006, electric rate adjustment moratoriums and power supply contracts expire in Ameren’s regulatory jurisdictions. |
| · | Approximately 11 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 early 2006. Most of Genco’s other wholesale and retail electric power supply agreements also expire during 2006 and substantially all of these are below market prices for similar contracts in early 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers in 2007 through an auction. This approval is subject to court appeal. |
| · | Certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties have sought and continue to seek various methods, including rate freeze legislation, to block the power procurement auction and/or the recovery of related costs for power supply resulting from the auction through rates to customers. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power costs from their electric customers in a timely manner could result in material adverse consequences for these companies and for Ameren. CIPS, CILCO and IP are willing to work with stakeholders to ease the burden of higher energy prices on residential customers through a rate increase phase-in plan, as long as such plan allows for the full and timely recovery of costs and does not adversely impact credit ratings. In March 2006, legislation was introduced in the Illinois House of Representatives that would allow the deferral of a portion of the power procurement costs and would authorize the ICC to permit a utility with fewer than one million retail customers to form special purpose finance vehicles to issue securitization bonds to recover the deferred costs, with interest. |
| · | The Ameren Illinois utilities filed proposed new tariffs with the ICC in December 2005 that would increase annual revenues from electric delivery services, effective January 2, 2007, by $156 million (CIPS - $14 million, CILCO - $33 million, IP - $109 million) per year commencing in 2007 and an additional $46 million (CILCO - $10 million, IP - $36 million per year) per year commencing in 2008. In April 2006, the ICC staff recommended increases in revenues for electric delivery services for Ameren of $71 million (CIPS - $8 million decrease, CILCO - $17 million increase and IP - $62 million increase) and the Illinois attorney general and CUB recommended increases in revenues for electric delivery services of $72 million for Ameren (CIPS - $7 million decrease, CILCO - $19 million increase and IP - $59 million increase). Other parties also made recommendations in the case. The ICC has until November 2006 to render a decision in these rate cases. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report. |
| · | In accordance with an August 2002 MoPSC order, UE submitted a confidential electric cost-of-service study to the MoPSC staff and others in December 2005. The study was based on a test year of the twelve months ending June 30, 2005. This submission did not constitute an electric rate adjustment request, but UE expects to file to adjust electric rates in Missouri in 2006. In an early May 2006 meeting before the MoPSC, UE committed to file to adjust rates in Missouri by July 10, 2006, if the MoPSC staff continued to support a test year ending June 30, 2006, with updates through January 1, 2007, including known and measureable fuel and purchased power costs. Another meeting before the MoPSC is expected later in May to further discuss the timing of potential rate actions related to UE. The MoPSC staff and other stakeholders will review any UE rate adjustment request and, after their analyses, may also make recommendations as to electric rate adjustments. Generally, a proceeding to change rates in Missouri could take up to 11 months. |
| · | We expect continued economic growth in our service territory to benefit energy demand in 2006 and beyond, but higher energy prices could result in reduced demand from consumers. |
| · | UE, Genco and CILCO are seeking to raise the equivalent availability and capacity factors of their power plants through a process improvement program. |
| · | Very volatile power prices in the Midwest affect the amount of revenues UE, Genco and CILCO (through AERG) can generate by marketing power into the wholesale and interchange markets and influence the cost of power we purchase in the interchange markets. |
| · | On April 1, 2005, the MISO Day Two Energy Market began operating. The MISO Day Two Energy Market presents an opportunity for increased power sales from UE, Genco and CILCO power plants and improved access to power for UE, CIPS, CILCO and IP. |
Fuel and Purchased Power
| · | In 2005, 86% of Ameren’s electric generation (UE - 80%, Genco - 96%, CILCO - 99%) was supplied by its coal-fired power plants. About 85% of the coal used by these plants (UE - 96%, Genco - 62%, CILCO - 77%) was delivered by railroads from the Powder River Basin in Wyoming. In May 2005, the joint Burlington Northern-Union Pacific rail line in the Powder River Basin 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. Because of the railroad delivery problems, UE, Genco and CILCO received only about 90% to 95% of scheduled deliveries of Powder River Basin coal in 2005. The impact of the coal delivery issues on inventory levels was exacerbated by warm summer weather and high power prices, which caused UE, Genco and CILCO plants to run more and to burn record amounts of coal. Maintenance on the rail lines into the Powder River Basin is expected to continue in 2006, but to have less of an impact on deliveries than in 2005. Further disruptions in coal deliveries could cause UE, Genco and CILCO to pursue a strategy that could include reducing sales of power during low-margin periods, utilizing higher-cost fuels to generate required electricity and purchasing power. |
| · | Ameren’s coal and related transportation costs are expected to increase 10% to 15% in 2006 and an additional 15% to 20% in 2007. In addition, power generation from higher-cost gas-fired plants is expected to increase in the next few years. See Item 3 - Quantitative and Qualitative Disclosures about Market Risk for information about the percentage of fuel and transportation requirements that are price-hedged for 2006 through 2010. |
| · | The MISO Day Two Energy Market resulted in significantly higher MISO-related costs in 2005. In part, these higher charges were due to volatile summer weather patterns and related loads. In addition, we attribute some of these higher charges to the relative infancy of the MISO Day Two Energy Market, suboptimal dispatching of power plants, and price volatility. We will continue to optimize our operations and work closely with MISO to ensure that the MISO Day Two Energy Market operates more efficiently and effectively in the future. |
| · | In July 2005, a new law was enacted that enables the MoPSC to put in place fuel, purchased power, and environmental cost recovery mechanisms for Missouri’s utilities. The law also includes rate case filing requirements, a 2.5% annual rate increase cap for the environmental recovery mechanism, and prudency reviews, among other things. Detailed rules for these |
mechanisms are expected to be effective in the second half of 2006.
| · | In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. The incident is being investigated by FERC and state authorities. UE expects the results of these reviews later in 2006. The facility will remain out of service until reviews by FERC and state authorities are concluded, further analyses are completed, and input is received from key stakeholders as to how and whether to rebuild the facility. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through most, if not all, of 2008. |
UE has accepted responsibility for the effects of the incident. At this time, UE believes that substantially all of the damage and liabilities caused by the breach will be covered by insurance. UE expects the total cost for damage and liabilities resulting from the Taum Sauk incident to range from $53 million to $73 million. As of March 31, 2006, UE had paid $18 million and accrued a $35 million liability, while expensing $1 million for the insurance deductible and recording a $52 million receivable due from insurance companies. No amounts have been recognized in the financial statements relating to estimated costs to repair or rebuild the facility. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers.
As a result of this breach, UE may be subject to litigation by private parties or by state or federal authorities. Until the reviews conducted by state and federal authorities have concluded, the insurance review is completed, a decision whether the plant will be rebuilt is made and future regulatory treatment for the plant is determined, among other things, we are unable to determine the impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already accrued.
| · | UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage is in 2007. During an outage, which occurs every 18 months, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases, versus non-outage years. |
| · | Over the next few years, we expect rising employee benefit costs as well as higher insurance and security costs associated with additional measures we have taken, or may need to take, at UE’s Callaway nuclear plant and our other facilities. Insurance premiums may also increase as a result of the Taum Sauk incident. |
| · | We are currently undertaking cost reduction and control initiatives associated with the strategic sourcing of purchases and streamlining of all aspects of our business. |
Capital Expenditures
| · | The EPA has issued more stringent emission limits on all coal-fired power plants. Between 2006 and 2016, Ameren expects that certain Ameren Companies will be required to invest between $2.1 billion and $2.9 billion to retrofit their power plants with pollution control equipment. More stringent state regulations could increase these costs. These investments will also result in higher ongoing operating expenses. Approximately 55% to 60% of this investment will be in Ameren’s regulated UE operations, and therefore it is expected to be recoverable over time from ratepayers. The recoverability of amounts expended in non-rate-regulated operations will depend on whether market prices for power adjust as a result of this increased investment. |
| · | In March 2006, UE completed the purchase of three gas-fired CT facilities with a capacity of nearly 1,500 megawatts in transactions valued at $292 million. The purchase of these facilities is designed to meet UE’s increased generating capacity needs and to provide additional flexibility in determining future baseload generating capacity additions. UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity, but at this time does not expect to require new baseload generation capacity until at least 2015. |
Affiliate Transactions
| · | Due to a MoPSC order issued in conjunction with the transfer of UE’s Illinois service territory to CIPS, UE and Genco amended an agreement to jointly dispatch electric generation in January 2006. In 2005, such an amendment probably would have resulted in a transfer of electric margins from Genco to UE of $35 million to $45 million based on certain assumptions and historical results. Ameren’s consolidated earnings could be affected when electric rates for UE are adjusted by the MoPSC to reflect the change in revenue. The Missouri OPC intervened in the FERC proceeding considering approval of the proposed amendment and requested that the joint dispatch agreement be further amended to price all transfers at market prices rather than incremental cost, which could transfer additional electric margins from Genco to UE. In March 2006, FERC rejected the Missouri OPC’s request for further amendment. The ultimate impact of the amendment will be determined by whether the joint dispatch agreement continues to exist, 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. See Risk Factors under Part II, Item 1A and Note 2 - Rate and |
| | Regulatory Matters and Note 7 - Related Party Transactions to our financial statements under Part I, Item 1, of this report for a discussion of the modification to the joint dispatch agreement ordered by the MoPSC and the amendment sought by the Missouri OPC and rejected in the FERC proceeding. |
| · | On December 31, 2005, a power supply agreement for UE, CIPS and IP with EEI expired. Power supplied under the agreement by EEI to UE, CIPS and IP was priced at EEI’s cost. The expiration of this agreement may require UE, Genco (as a result of its power supply agreement with CIPS) and IP to incur higher fuel or purchased power costs. Power previously supplied under this agreement to UE, CIPS and IP will be sold at market prices. Market prices in early 2006 were above EEI’s cost to produce power. See Note 7 - Related Party Transactions to our financial statements under Part I, Item 1, of this report for a further discussion of the EEI power supply agreement. |
Recent Acquisitions
| · | Ameren, CILCORP, CILCO and IP expect to focus on realizing integration synergies associated with these acquisitions, including utilizing more economical fuels at CILCORP and CILCO and reducing administrative and operating expenses at IP. |
Other
| · | In August 2005, President George W. Bush signed into law the Energy Policy Act of 2005. This legislation includes several provisions that affect the Ameren Companies, including the repeal of PUHCA 1935 (under which Ameren was registered) effective in February 2006, 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 above items could have a material impact on our results of operations, financial position, or liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, or liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s 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.
REGULATORY MATTERS
See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Market risk is 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 part of the following discussion.
Our risk management objective is to optimize our physical generating assets within prudent risk parameters. Our risk management policies are set by a Risk Management Steering Committee, which is comprised of senior-level Ameren officers.
Except as discussed below, there have been no material changes to the quantitative and qualitative disclosures about market risk in the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005. See Item 7A under Part II of the 2005 Form 10-K for a more detailed discussion of our market risks.
Interest Rate Risk
We are exposed to market risk through changes in interest rates. The following table presents the estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 1% on variable-rate debt outstanding at March 31, 2006:
| | Interest Expense | | Net Income(a) | |
| Ameren | $ | 14 | | $ | (9 | ) |
| UE | | 9 | | | (5 | ) |
| CIPS | | (b | ) | | (b | ) |
| Genco | | 2 | | | (1 | ) |
| CILCORP | | 4 | | | (2 | ) |
| CILCO | | 2 | | | (1 | ) |
| IP | | 4 | | | (3 | ) |
| (a) | Calculations are based on an effective tax rate of 38%. |
| (b) | Less than $1 million. |
The model does not consider potential reduced overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would probably act to further mitigate our exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. NYMEX-traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. 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 March 31, 2006, 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, IP and Marketing Company may have credit exposure associated with interchange purchase and sale activity with nonaffiliated companies. At March 31, 2006, UE’s, Genco’s, IP’s and Marketing Company’s combined credit exposure to non-investment-grade counterparties related to interchange purchases and sales was $1 million, net of collateral. We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program that involves daily exposure reporting to senior management, master trading and netting agreements, and credit support, such as letters of credit and parental guarantees. We also analyze each counterparty’s financial condition before we enter into sales, forwards, swaps, futures or option contracts, and we monitor counterparty exposure associated with our leveraged leases. We estimate our credit exposure to MISO associated with the MISO Day Two Energy Market to be $32 million at March 31, 2006.
Equity Price Risk
Our costs of providing defined benefit retirement and postretirement benefit plans are dependent on 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 in the amount of cash required to be contributed to the plans.
Commodity Price Risk
We are exposed to changes in market prices for electricity, fuel, and natural gas. UE’s, Genco’s, AERG’s and EEI’s risks of changes in prices for power sales are partially hedged through sales agreements to regulated and unregulated electric customers. Most of Genco’s and AERG’s electric power sales agreements expire during 2006. EEI’s cost-based power supply agreements for nearly all of its power expired at the end of 2005. EEI now has a contract to sell all its power to Marketing Company at market prices through December 31, 2015. EEI currently does not expect to hedge for price risk a significant portion of its available megawatthours. Genco and AERG will probably participate jointly in the September 2006 Illinois power procurement auction through Marketing Company. Genco and AERG will also seek to sell power forward to wholesale, municipal and industrial customers as has been its past practice. Ultimately, Genco and AERG will seek to hedge for price risk the majority of available megawatthours for 2007 by December 31, 2006. We also attempt to mitigate financial risks through structured risk management programs and policies, through structured forward-hedging programs, and through derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts). A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset.
CIPS, CILCO and IP have electric rate freezes in Illinois through January 1, 2007, and power supply contracts in place through December 31, 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers in 2007 through a September 2006 auction. The approved framework also allows for full cost recovery of power through a rate mechanism. UE has an electric rate freeze in Missouri through June 30, 2006, and is also exposed to price risk on its interchange sales. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for further information.
The following table presents the percentages of the projected required supply of coal and coal transportation for our coal-fired power plants, nuclear fuel for UE’s Callaway nuclear plant, natural gas for our CTs and retail distribution, as appropriate, and purchased power needs of CIPS, CILCO and IP, which own virtually no generation, that are price-hedged over the remainder of 2006 through 2010:
| | 2006 | | 2007 | | 2008 - 2010 | |
Ameren: | | | | | | | | | |
| Coal | | 100 | % | | 93 | % | | 55 | % |
| Coal transportation | | 100 | | | 93 | | | 60 | |
| Nuclear fuel | | 100 | | | 100 | | | 69 | |
| Natural gas for generation | | 58 | | | 10 | | | 1 | |
Natural gas for distribution(a) | | (a | ) | | 33 | | | 6 | |
UE: | | | | | | | | | |
| Coal | | 100 | % | | 94 | % | | 51 | % |
| Coal transportation | | 100 | | | 98 | | | 79 | |
| Nuclear fuel | | 100 | | | 100 | | | 69 | |
| Natural gas for generation | | 39 | | | 5 | | | 1 | |
Natural gas for distribution(a) | | (a | ) | | 25 | | | 5 | |
CIPS: | | | | | | | | | |
Natural gas for distribution(a) | | (a | ) | | 41 | % | | 13 | % |
Purchased power(b) | | 100 | | | - | | | - | |
Genco: | | | | | | | | | |
| Coal | | 100 | % | | 90 | % | | 65 | % |
| Coal transportation | | 100 | | | 89 | | | 38 | |
| Natural gas for generation | | 100 | | | 12 | | | 2 | |
CILCORP/CILCO: | | | | | | | | | |
| Coal | | 100 | % | | 95 | % | | 53 | % |
| Coal transportation | | 100 | | | 67 | | | 44 | |
Natural gas for distribution(a) | | (a | ) | | 38 | | | 5 | |
Purchased power(b) | | 100 | | | - | | | - | |
IP: | | | | | | | | | |
Natural gas for distribution(a) | | (a | ) | | 30 | % | | 3 | % |
Purchased power(b) | | 90 | | | - | | | - | |
| (a) | Represents the percentage of natural gas price-hedged for the peak winter season of November through March. The year 2006 represents the period January 2006 through March 2006 and therefore is non-applicable (n/a) for this report. The year 2007 represents November 2006 through March 2007. This continues each successive year through March 2010. |
| (b) | Beginning in 2007, CIPS, CILCO and IP are expected to purchase all electric capacity and energy through a power procurement auction process approved by the ICC. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a discussion of this matter. |
The following table shows how our total fuel expense might increase and how our net income might decrease if coal and coal transportation costs were to increase by 1% on any requirements not currently covered by fixed-price contracts for the remainder of 2006 through 2010:
| | Coal | | Transportation | |
| | Fuel Expense | | Net Income(a) | | Fuel Expense | | Net Income(a) | |
| Ameren | $ | 10 | | $ | (6 | ) | $ | 10 | | $ | (6 | ) |
| UE | | 6 | | | (3 | ) | | 3 | | | (2 | ) |
| Genco | | 3 | | | (2 | ) | | 4 | | | (3 | ) |
| CILCORP/CILCO | | 1 | | | (1 | ) | | 2 | | | (1 | ) |
| (a) | Calculations are based on an effective tax rate of 38%. |
In the event of a significant change 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, this sensitivity analysis assumes no change in our financial structure or fuel sources. As discussed in Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report, Missouri legislation has been approved that could mitigate the impact of increased fuel cost at Ameren and UE through UE’s ability to recover these increases in rates.
See Note 8 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for further information.
Fair Value of Contracts
Most of our commodity contracts qualify for treatment as normal purchases and normal sales. We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the quarter ended March 31, 2006. The sources used to determine the fair value of these contracts were active quotes, other external sources, and other modeling and valuation methods. All of these contracts have maturities of less than four years.
| | Ameren(a) | | UE | | CIPS | | CILCORP/ CILCO | | IP | |
| Fair value of contracts at beginning of period, net | $ | 69 | | $ | (5 | ) | $ | 12 | | $ | 50 | | $ | (2 | ) |
| Contracts realized or otherwise settled during the period | | (12 | ) | | (2 | ) | | (3 | ) | | (4 | ) | | (1 | ) |
Changes in fair values attributable to changes in valuation technique and assumptions | | - | | | - | | | - | | | - | | | - | |
| Fair value of new contracts entered into during the period | | - | | | 1 | | | - | | | - | | | - | |
| Other changes in fair value | | (27 | ) | | 3 | | | (3 | ) | | (22 | ) | | 5 | |
| Fair value of contracts outstanding at end of period, net | $ | 30 | | $ | (3 | ) | $ | 6 | | $ | 24 | | $ | 2 | |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
ITEM 4. CONTROLS AND PROCEDURES.
| (a) | Evaluation of Disclosure Controls and Procedures |
As of March 31, 2006, the principal executive officer and principal financial officer of each of the Ameren Companies have evaluated the effectiveness of the design and operation of each registrant’s disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Exchange Act). Upon making 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.
| (b) | Change in Internal Controls |
There has been no change in the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, their internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses.
Note 2 - Rate and Regulatory Matters, Note 7 - Related Party Transactions and Note 8 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report contain information on legal and administrative proceedings which are incorporated by reference under this item.
ITEM 1A. RISK FACTORS.
The Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005, includes a detailed discussion of our risk factors. The information presented below updates and should be read in conjunction with the risk factors and information disclosed in that Form 10-K.
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 lawmakers and regulators that can significantly adversely affect our prospective earnings, liquidity, or 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, or 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 entities outside of our control, including the MoPSC, the ICC, and FERC. Decisions made by these entities could have a material adverse impact on our businesses including our results of operations, financial position, or liquidity.
As a part of the settlement of UE’s Missouri electric rate case in August 2002, UE is subject to a rate moratorium that prohibits changes in its electric rates in Missouri before July 1, 2006. Furthermore, as part of the settlement of UE’s Missouri gas rate case, which was approved by the MoPSC in January 2004, UE agreed to make no changes in its gas delivery rates prior to July 1, 2006, with certain exceptions. In late December 2005, UE submitted a confidential cost-of-service study based on a test year of the twelve months ending June 30, 2005. This submission did not constitute an electric rate adjustment request, but UE expects to file to adjust electric rates in Missouri in 2006. In an early May 2006 meeting before the MoPSC, UE committed to file to adjust rates in Missouri by July 10, 2006, if the MoPSC staff continued to support a test year ending June 30, 2006, with updates through January 1, 2007, including known and measureable fuel and purchased power costs. Another meeting before the MoPSC is expected later in May to further discuss the timing of potential rate actions related to UE. The MoPSC staff and other stakeholders will review any UE rate adjustment request and, after their analyses, may also make recommendations as to electric rate adjustments. Generally, a proceeding to change rates in Missouri could take up to 11 months.
The ICC order approving Ameren’s acquisition of IP prohibited IP from filing for any increase in gas delivery rates effective before January 1, 2007, beyond IP’s then-pending request for a gas delivery rate increase. In addition, a provision of the Illinois Customer Choice Law related to the restructuring of the Illinois electric industry put a rate freeze into effect through January 1, 2007, for CIPS, CILCO and IP. This Illinois legislation also requires that 50% of the earnings from each respective jurisdiction in excess of certain levels be refunded to CIPS’, CILCO’s and IP’s Illinois customers through 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers in 2007 through an auction and related tariffs. This approval is subject to a pending court appeal. In addition, certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties have sought and continue to seek to block the power procurement auction and/or the recovery, through rates to customers, of related costs for power supply resulting from the auction. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power costs from their electric customers in a timely manner could result in material adverse consequences for these companies and for Ameren, including a significant drop in credit ratings (possibly to below investment-grade status), a loss of access to the capital markets, higher borrowing costs, higher power supply costs, an inability to make timely energy infrastructure investments, impaired customer service, job losses, and financial insolvency.
The Illinois legislature held hearings in 2005 and 2006 regarding the framework for retail rate determination and power procurement. In February 2006, legislation was introduced in the Illinois House of Representatives that would extend the electric rate freeze in Illinois through 2010. CIPS, CILCO and IP strongly believe that an extension of the electric rate freeze in Illinois would not be in the best interests of any of the Ameren Illinois utilities or their customers, and have been working with key stakeholders in Illinois to develop a constructive rate increase phase-in plan for residential customers to address the potential significant increases in customer rates for our Illinois utilities beginning in 2007. We believe that a rate increase phase-in plan would need to allow for deferral of a portion of the power procurement costs, with provision for full and timely recovery of all deferred costs in a manner that would not result in further reductions in credit ratings from December 31, 2005 levels. We believe a rate increase phase-in plan, providing for deferral of costs with certainty of full and timely recovery of any deferred costs, would require legislation in Illinois. In March 2006, legislation was introduced in the Illinois House of Representatives that would allow the deferral of a portion of the power procurement costs and would authorize the ICC to permit utilities with fewer than one million retail customers to form special purpose finance vehicles to issue securitization bonds to recover the deferred costs, with interest. CIPS, CILCO and IP each have less than one million retail customers. Securitization would allow these special purpose vehicles to issue debt securities and use the proceeds to pay the utilities immediately upon issuance of the bonds for the deferred power costs for which the utilities did not receive reimbursement from customers during a phase-in deferral period. Customers would fund, through dedicated charges included in electric bills, a future
payment stream that would be used to service the securitized debt. In effect, through these charges utility customers would pay in the future for power used, but not paid for, during a phase-in deferral period. This approach has the effect of spreading over the life of the bonds, a period of up to 10 years, the potentially significant initial electric rate increase for residential customers that would otherwise be necessary to pay the costs on a current basis, and we believe assisting our Ameren Illinois utilities in maintaining their financial integrity. We cannot predict what actions, if any, the Illinois legislature may ultimately take. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power costs from their electric customers in a timely manner could result in material adverse consequences for these companies and for Ameren.
Ameren, CIPS, CILCO and IP will continue to explore a number of legal and regulatory actions, strategies and alternatives to address these Illinois electric issues. There can be no assurance that Ameren and the Ameren Illinois utilities will prevail over the stated opposition by certain Illinois legislators, the Illinois attorney general, the Illinois governor and other stakeholders, or that the legal and regulatory actions, strategies and alternatives that Ameren and the Ameren Illinois utilities are considering will be successful.
In December 2005, the Ameren Illinois utilities filed with the ICC proposed new tariffs that would increase revenues from electric delivery services, effective January 2, 2007, based on a proposed residential rate phase-in plan, by $156 million (CIPS - $14 million, CILCO - $33 million, IP - $109 million) per year commencing in 2007 and an additional $46 million (CILCO - $10 million, IP - $36 million) per year commencing in 2008. In April 2006, the ICC staff recommended increases in revenues for electric delivery services for Ameren of $71 million (CIPS - $8 million decrease, CILCO - $17 million increase and IP - $62 million increase) and the Illinois attorney general and CUB recommended increases in revenues for electric delivery services for Ameren of $72 million (CIPS - $7 million decrease, CILCO - $19 million increase and IP - $59 million increase). Other parties also made recommendations in the case. These proposed tariffs are subject to approval of, and reduction by, the ICC, which is expected to rule by November 2006. We cannot predict the outcome of these proceedings.
As a part of the settlement of UE’s Missouri electric rate case in 2002, UE made a commitment to make $2.25 billion to $2.75 billion in critical energy infrastructure investments 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 at least July 1, 2006, for UE and January 2, 2007, for CIPS, CILCO and IP. In the current climate of rate reductions and rate moratoriums, any new energy infrastructure and new programs could result in increased financing requirements for UE, CIPS, CILCO and IP. This could have a material impact on our results of operations, financial position, or liquidity.
The Ameren Companies do not currently have, in either Missouri or Illinois, a rate adjustment clause for their electric operations that would allow them to recover the costs for purchased power or increased fuel costs from customers. Therefore, insofar as 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.
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, FERC has been mandating changes in the regulatory framework for transmission-owning public utilities such as UE, CIPS, CILCO and IP.
Principally because of rate reductions and moratoriums, and increased costs and investments have caused decreased returns in Ameren’s distribution utility businesses. 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, including phase-in plans. Any or all of these could have a significant adverse effect on our results of operations, financial position, or liquidity.
UE, CIPS and Genco are parties to an agreement to jointly dispatch power. Modification or termination of this agreement could result in the transfer of electric margins from Genco to UE and the reduction of electric margins at Ameren.
Genco and UE have an agreement to dispatch their generating facilities jointly. Recently completed, ongoing or future federal and state regulatory proceedings and policies, among other things, may evolve in ways that could affect Genco’s and UE’s ability to participate in this affiliate arrangement on current terms. For example, as a result of the February 2005 MoPSC order approving the transfer of UE’s Illinois service territory to CIPS in 2005, the provision in the joint dispatch agreement which determines the allocation between UE and Genco of margins or profits from short-term sales of excess generation to third parties had to be modified. Specifically, the MoPSC order required an amendment so that margins on third-party short-term sales of excess generation to third parties had to be modified. Specifically, the MoPSC order required an amendment so that margins on third-party short-term
power sales of excess generation would be allocated between UE and Genco based on generation output, not on load requirements, as the agreement had provided. In compliance with the MoPSC order, UE, CIPS and Genco, on January 9, 2006, filed this amendment to the joint dispatch agreement with FERC for its approval.
The Missouri OPC intervened in the FERC proceeding and requested that the joint dispatch agreement be further amended to price all transfers of power between Genco and UE at market prices rather than incremental cost, which could transfer additional electric margins from Genco to UE. In March 2006, FERC denied the Missouri OPC request and approved the amendment filed by UE, CIPS and Genco effective January 10, 2006. This change in the allocation methodology resulted in a $9 million transfer of electric margins from Genco to UE during the first quarter of 2006.
Should the joint dispatch agreement be modified to price transfers at market prices as a result of some future regulatory proceeding (for example, by the MoPSC in a ratemaking proceeding), or otherwise, an evaluation of the continued benefits of the joint dispatch agreement would have to be made by UE, CIPS and Genco. Depending on the outcome of the evaluations, one or more of these companies may decide to terminate the agreement. UE, CIPS and Genco have the right to terminate this agreement with one year’s notice, unless terminated earlier by mutual consent. Ameren, UE, CIPS and Genco cannot predict whether any additional actions may be taken by regulatory agencies on this matter in the future.
For the full year 2005, Genco received net transfers of 8.7 million megawatthours of power from UE. In 2005, Genco sold 2.9 million megawatthours of power to UE, generating revenue of $74 million, and purchased 11.6 million megawatthours from UE at a cost of $230 million. While it cannot be predicted what level of power purchases and sales will occur between the two companies in the future, UE and Genco believe that under normal operating conditions, the level of net transfers under the joint dispatch agreement from UE to Genco will decline in 2006 from 2005 levels, which was a historical high, due to less excess generation being available at UE. This is expected to result from greater native load demand in 2006 at UE, resulting from the addition of Noranda as a customer in June 2005, continued organic growth, and the expiration of a cost-based EEI power supply contract with UE, among other things. A cost-based EEI power supply contract with CIPS (which had been assigned to Genco through Marketing Company) also expired on December 31, 2005. CIPS load previously served by EEI and additional CIPS load created by the transfer of UE’s Illinois service territory to CIPS in May 2005 is being served by other available Genco resources, including generation available pursuant to the joint dispatch agreement, beginning January 1, 2006.
By the end of 2006, Genco’s electric power supply agreements with its primary customer, CIPS (through Marketing Company), and most of its wholesale and retail customers will expire. Strategies for participation in the expected CIPS, CILCO and IP September 2006 power procurement auction, and for sales to other customers for 2006 and beyond, are currently being developed and implemented. In the event the joint dispatch agreement is terminated or amended to price all transfers at market prices, the amount of generation available to Genco from its own power plants will determine the amount of power it will offer into the power procurement auction and to wholesale, retail and interchange customers. As a result, we would expect future sales volumes from Genco to be lower than prior years, and related fuel and purchased power costs to increase. However, Genco believes that future sales may be contracted at higher prices since the power supply agreement between CIPS and Genco and substantially all of the other wholesale and retail contracts that expire in 2006 are below market prices for similar contracts in early 2006. Due to all of these factors, the ultimate impact of the potential changes to Genco’s results of operations, financial position, or liquidity are unable to be determined at this time; however, the impact could be material.
If the joint dispatch agreement did not exist or was amended to price all transfers at market prices, UE may be able to retain the net transfers of power that are currently going to Genco under the joint dispatch agreement and could sell this power in the interchange market at market prices, instead of incremental cost. At certain times, UE may also be required to use power from its own higher-cost power plants or purchase power to meet its load requirements. The margin impact to UE of the potential termination of the joint dispatch agreement or an amendment to price all transfers at market prices has not been quantified, but UE believes it would significantly increase its electric margins. Any increase in UE’s electric margins as a result of actual or imputed changes to the joint dispatch agreement would likely result in a decrease in UE’s revenue requirements in its next rate adjustment proceeding. The ultimate ratemaking treatment for the joint dispatch agreement will be determined in a future rate proceeding.
While UE’s and Genco’s results of operations, financial position, or liquidity could be materially impacted by an amendment to price all transfers at market prices or termination of the joint dispatch agreement, these changes would not have a material impact on CIPS. Further, Ameren’s earnings would be unaffected until electric rates for UE are adjusted by the MoPSC to reflect the impact of the proposed amendments or other changes to the joint dispatch agreement.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.
The following table presents Ameren Corporation’s purchases of equity securities reportable under Item 703 of Regulation S-K:
Period | (a) Total Number of Shares (or Units) Purchased(a) | | (b) Average Price Paid per Share (or Unit) | | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs |
| January 1 - January 31, 2006 | | 22,150 | | $ | 51.51 | | | - | | | - |
| February 1 - February 28, 2006 | | 1,830 | | | 50.76 | | | - | | | - |
| March 1 - March 31, 2006 | | 79,303 | | | 50.45 | | | - | | | - |
| Total | | 103,283 | | $ | 50.68 | | | - | | | - |
| (a) | Included in January were 10,000 shares of Ameren common stock purchased by Ameren in open-market transactions pursuant to Ameren’s Long-term Incentive Plan of 1998 in satisfaction of Ameren’s obligations for director compensation awards. Included in March were 79,303 shares of Ameren common stock purchased by Ameren from employee participants to satisfy participants’ tax obligations incurred by the release of restricted shares of Ameren common stock under the Long-term Incentive Plan of 1998. The remaining shares of Ameren common stock were purchased by Ameren in open-market transactions in satisfaction of Ameren’s obligation upon the exercise by employees of options issued under Ameren’s Long-term Incentive Plan of 1998. Ameren does not have any publicly announced equity securities repurchase plans or programs. |
None of the other registrants purchased equity securities reportable under Item 703 of Regulation S-K during the January 1 to March 31, 2006, period.
ITEM 6. EXHIBITS.
(a) Exhibits. The documents listed below are being filed on behalf of Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP as indicated.
Martin J. Lyons
Martin J. Lyons
Martin J. Lyons
Martin J. Lyons
Martin J. Lyons
