ITEM 1.
BUSINESS
GENERAL
We are a non-rate-regulated electric generation subsidiary of AER, which is a subsidiary of Ameren Corporation. Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren's primary assets are its equity interests in its subsidiaries. Ameren's subsidiaries, like us, are separate, independent legal entities with separate businesses, assets, and liabilities.
We are headquartered in Collinsville, Illinois and were incorporated in Illinois in March 2000. We own and operate a merchant generation business in Illinois. Much of our business was formerly owned and operated by CIPS. In 2000, we acquired from CIPS, at net book value, its coal-fired electric energy centers. Since then, we have constructed or purchased from other affiliates natural gas-fired energy centers. We have an 80% ownership interest in EEI that AER transferred to us in 2010, at net book value. We consolidate EEI for financial reporting purposes. EEI operates merchant electric generation facilities and FERC regulated transmission facilities in Illinois. We also consolidate our wholly owned subsidiary, Coffeen and Western Railroad Company, for financial reporting purposes.
In December 2012, Ameren determined that it intended to, and it was probable that it would, exit its merchant generation business, of which we are a part. Based on the expectation of reduced financial support from Ameren, together with existing power market conditions and cash flow requirements, we estimated it was more likely than not that we would sell the Elgin energy center for liquidity purposes within two years. This change in assumption resulted in a noncash long-lived asset impairment charge during the fourth quarter of 2012. See Note 11 - Impairment and Other Charges under Part II, Item 8, of this report for additional information.
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Immediately prior to Ameren’s entry into the transaction agreement with IPH on March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. Both March 2013 transactions are regarded as subsequent events to the accompanying December 31, 2012 consolidated financial statements. See Note 12 - Subsequent Events under Part II, Item 8, of this report for additional information.
As of December 31, 2012, we had 477 employees. As of January 1, 2013, the IBEW and the IUOE collectively represented about 71% of total employees. The collective bargaining agreements have four-year terms and expire in 2015.
For additional information about the development of our business, our business operations, and factors affecting our operations and financial position, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report and Note 1 - Summary of Significant Accounting Policies under Part II, Item 8, of this report.
RATES AND REGULATIONS
Revenues are determined by market conditions and contractual arrangements. We expect our energy centers to have 4,462 megawatts of capacity available for the 2013 peak summer electrical demand. As discussed below, we sell all of our power and capacity to Marketing Company through PSAs. Marketing Company attempts to optimize the value of our available generation capacity and energy and to mitigate risks through a
variety of techniques, including wholesale sales of capacity and energy, retail sales in the non-rate-regulated Illinois market, spot market sales primarily in MISO and PJM, and financial hedging transactions, including options and other derivatives. Marketing Company enters into long-term and short-term contracts. For additional information, see Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 2 - Related Party Transactions and Note 8 - Derivative Financial Instruments under Part II, Item 8, of this report.
General Regulatory Matters
We must receive FERC approval to enter into various transactions, including to conduct certain acquisitions, mergers, consolidations, and divestitures involving assets subject to FERC jurisdiction, such as generation and transmission facilities.
We are also subject to mandatory reliability standards, including cybersecurity standards, adopted by FERC to ensure the reliability of the bulk power electric system. These standards are developed and enforced by NERC pursuant to authority given to it by the FERC. If we or any of our subsidiaries were found not to be in compliance with any of these mandatory reliability standards, we could incur substantial monetary penalties and other sanctions.
Environmental Matters
Certain of our operations are subject to federal, state, and local environmental statutes or regulations relating to the safety and health of personnel, the public, and the environment. These environmental statutes and regulations include requirements for identification, generation, storage, handling, transportation, disposal, recordkeeping, labeling, reporting, and emergency response in connection with hazardous and toxic materials; safety and health standards; and environmental protection requirements, including standards and limitations relating to the discharge of air and water pollutants, the protection of natural and cultural resources, and the management of waste and byproduct materials. Failure to comply with those statutes or regulations could have material adverse effects on us. We could be subject to criminal or civil penalties by regulatory agencies or we could be ordered by the courts to pay private parties. Except as indicated in this report, we believe that we are in material compliance with existing statutes and regulations.
In addition to existing laws and regulations, including the Illinois MPS, the EPA is developing environmental regulations that will have a significant impact on electricity generators. These regulations could be particularly burdensome for certain companies, including ours, that operate coal-fired energy centers. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised national ambient air quality standards for SO2 and NO2 emissions; the CSAPR, which would have required further reductions of SO2 emissions, NOx emissions, and fine particulate matter emissions from energy centers; a regulation that governs management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, toxic
metals, and acid gases from energy centers; revised NSPS for particulate matter, SO2, and NOx emissions from new sources; and new regulations under the Clean Water Act that could require significant capital expenditures, such as for new water intake structures or cooling towers, at our energy centers. The EPA has proposed CO2 limits for new coal-fired and natural gas-fired combined cycle units and is expected to propose limits for existing units in the future. These new and proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation as well as the timing of any such implementation is uncertain, as evidenced by the CSAPR being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia in August 2012. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and/or increased operating costs over the next five to ten years. Compliance with these environmental laws and regulations could be prohibitively expensive. If they are, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.
The decision to make pollution control equipment investments depends on whether the expected future market price for power reflects the increased cost for environmental compliance. During early 2012, the observable market price for power for delivery in that year and in future years sharply declined below 2011 levels primarily because of declining natural gas prices, as well as the impact from the stay of the CSAPR. As a result of this sharp decline in the market price for power, as well as uncertain environmental regulations, we decelerated the construction of two scrubbers at our Newton energy center.
For additional discussion of environmental matters, including NOx, SO2, and mercury emission reduction requirements, remediation efforts, and a discussion of the EPA’s allegations of violations of the Clean Air Act and the EPA’s Notice of Violation of permitting requirements at our Newton energy center, see Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 10 - Commitments and Contingencies under Part II, Item 8, of this report.
TRANSMISSION AND SUPPLY OF ELECTRIC POWER
Ameren owns an integrated transmission system. We are included in Ameren’s AMIL balancing authority within MISO. The AMIL balancing area excludes EEI and the Elgin CT energy center, which are discussed below. During 2012, the peak demand was 9,720 megawatts in AMIL.
EEI operates its own balancing authority area and its own transmission facilities in southern Illinois. The EEI transmission system is directly connected to the transmission systems of MISO, the Tennessee Valley Authority, and Louisville Gas and
Electric Company. EEI’s energy centers are dispatched separately from those of Genco. The Elgin CT energy center is included in PJM.
Genco and EEI are members of SERC. SERC is responsible for the bulk electric power supply system in all or portions of Missouri, Illinois, Arkansas, Kentucky, Tennessee, North Carolina, South Carolina, Georgia, Mississippi, Alabama, Louisiana, Virginia, Florida, Oklahoma, Iowa, and Texas. As a result of the Energy Policy Act of 2005, owners and operators of the bulk electric power system are subject to mandatory reliability standards promulgated by NERC and its regional entities, such as SERC, which are enforced by FERC. Genco and EEI must comply with these standards, which are in place to ensure the reliability of the bulk electric power system.
Power Supply Agreements
Genco (parent) has a PSA with Marketing Company, whereby it agreed to sell and Marketing Company agreed to purchase all of the capacity and energy available from its generation fleet. Marketing Company entered into a similar PSA with AERG. Under the PSAs, revenues allocated between Genco and AERG are based on reimbursable expenses and generation of each entity. Each PSA will continue through December 31, 2022, and from year to year thereafter unless either party to the respective PSA elects to terminate the PSA by providing the other party with no less than six months advance written notice.
EEI has a PSA with Marketing Company, whereby EEI agreed to sell and Marketing Company agreed to purchase all of the capacity and energy available from EEI’s generation fleet. The price that Marketing Company pays for capacity is set annually based upon prevailing market prices. Marketing Company pays spot market prices for the associated energy. In addition, EEI may at times purchase energy from Marketing Company to fulfill obligations to a nonaffiliated party. This PSA will continue through May 31, 2016, unless either party elects to terminate the PSA by providing the other party with no less than four years advance written notice or five days’ written notice in the event of a default, unless the default is cured within 30 business days.
POWER GENERATION
The following table presents the source of our electric generation, excluding purchased power, for the years ended December 31, 2012, 2011, and 2010:
(a)
Less than 1% of total fuel supply.
The following table presents the cost of fuels for our electric generation for the years ended December 31, 2012, 2011, and 2010:
(a)
The fuel cost for coal represents the cost of coal, the costs for transportation, which include railroad diesel fuel additives, and the cost of emission allowances.
(b)
The fuel cost for natural gas represents the cost of natural gas and firm and variable costs for transportation, storage, balancing, and fuel losses for delivery to the energy center. In addition, the fixed costs for firm transportation and firm storage capacity are included in the calculation of fuel cost for the energy centers.
(c)
Represents all costs for fuels used in our energy centers, to the extent applicable, including coal, natural gas, oil, and handling. Oil is not individually listed in this table because its use is minimal.
Coal
We have agreements in place to purchase a portion of the coal we need and to transport it to our energy centers through 2019. We expect to enter into additional contracts to purchase coal from time to time. Our forward coal requirements and coal supply agreements are dependent on the volume of power sales contracted. We strive to achieve increased margin certainty by aligning fuel purchases with power sales. Our energy centers burned 10.5 million tons of coal in 2012. See Part II, Item 7A - Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about coal supply contracts.
About 99% of our coal is purchased from the Powder River Basin in Wyoming. The remaining coal is typically purchased from the Illinois Basin. Inventory may be adjusted because of changes in burn or uncertainties of supply due to potential work stoppages, delays in coal deliveries, equipment breakdowns, and other factors. In the past, deliveries from the Powder River Basin have occasionally been restricted because of rail maintenance, weather, and derailments. As of December 31, 2012, coal inventories were at or above targeted levels. Disruptions in coal deliveries could cause us to pursue a strategy that could include reducing sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources.
Natural Gas Supply for Generation
To maintain deliveries to natural gas-fired energy centers throughout the year, especially during the summer peak demand, our portfolio of natural gas supply resources includes firm transportation capacity and firm no-notice storage capacity leased from interstate pipelines. We primarily use the interstate pipeline systems of Panhandle Eastern Pipe Line Company, Trunkline Gas Company, and Natural Gas Pipeline Company of America to transport natural gas to energy centers. In addition to physical transactions, we use financial instruments, including some in the NYMEX futures market and some in the OTC financial markets, to hedge the price paid for natural gas.
Our natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to our energy centers. This is accomplished by optimizing transportation and storage options and minimizing cost and price risk through various supply and price-hedging agreements that allow access to multiple gas pools, supply basins, and storage services. As of December 31, 2012, we have price-hedged about 59% of our expected natural gas supply requirements for generation in 2013.
For additional information on our fuel and our power supply agreements, see Results of Operations, Liquidity and Capital Resources and Effects of Inflation and Changing Prices in Management’s Discussion and Analysis of Financial Condition and Results of Operation under Part II, Item 7, of this report. Also see Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, of this report, Note 1 - Summary of Significant Accounting Policies, Note 2 - Related Party Transactions, Note 8 - Derivative Financial Instruments, and Note 10 - Commitments and Contingencies under Part II, Item 8, of this report.
INDUSTRY ISSUES
We are facing issues common to the merchant electric generation industry. These issues include:
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continually developing and complex environmental laws, regulations and issues, including air and water quality standards, mercury emissions standards, and likely greenhouse gas limitations and CCR management requirements;
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the potential for changes in laws, regulations, and policies at the state and federal level;
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access to, and uncertainty in, the capital and credit markets;
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cybersecurity risk, including loss of operational control of energy centers and/or loss of data, and compliance with related industry regulations;
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the potential for more intense competition in generation, supply and distribution, including new technologies;
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pressure on customer usage in light of current economic conditions and energy efficiency initiatives;
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the potential for reregulation in some states, which could cause electric distribution companies to build or acquire energy centers and to purchase less power from electric generation companies such as Genco;
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changes in the structure of the industry as a result of changes in federal and state laws;
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increases, decreases, and volatility in power prices due to the balance of supply and demand and marginal fuel costs;
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weakened financial strength of merchant generators, especially those with coal-fired energy centers, including their ability to generate positive cash flows in competitive markets as they seek to comply with environmental regulations;
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the availability of fuel and increases or decreases in fuel prices;
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the availability of qualified labor and material, and rising costs;
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legislation or proposals for programs to encourage or mandate energy efficiency and renewable sources of power; and
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consolidation of merchant generation companies.
We are monitoring these issues. Except as otherwise noted in this report, we are unable to predict what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see Risk Factors under Part I, Item 1A, and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 10 - Commitments and Contingencies under Part II, Item 8, of this report.
OPERATING STATISTICS
The following tables present our key operating statistics for the past three years:
AVAILABLE INFORMATION
We make available free of charge through Ameren’s website (www.ameren.com) our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, eXtensible Business Reporting Language (XBRL) documents, and any amendments to those reports filed with, or furnished to, the SEC pursuant to Sections 13(a) or 15(d) of the Exchange Act as soon as reasonably possible after such reports are electronically filed with, or furnished to, the SEC. These documents are also available through an Internet website maintained by the SEC (www.sec.gov). Financial and other material information regarding Genco is routinely posted and accessible at Ameren’s website.
Ameren also makes available free of charge through its website the charters of Ameren’s board of directors’ audit and risk committee, human resources committee, nominating and corporate governance committee, finance committee, and nuclear oversight and environmental committee; the corporate governance guidelines; a policy regarding communications to the board of directors; a policy and procedures with respect to related-person transactions; a code of ethics for principal executive and senior financial officers; a code of business conduct applicable to all directors, officers and employees; and a director nomination policy that applies to Ameren. The information on Ameren’s website, or any other website referenced in this report, is not incorporated by reference into this report.
ITEM 1A.
ITEM 1A.
RISK FACTORS
Investors should review carefully the following material risk factors and the other information contained in this report. The risks that we face are not limited to those in this section. There may be further risks and uncertainties that are not presently known or that are not currently believed to be material that may adversely affect our results of operations, financial position, and liquidity. See Forward-Looking Statements above and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report.
Required regulatory approvals may not be obtained in connection with Ameren’s divestiture of New AER to IPH or our sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, and either transaction may not be completed on the anticipated schedule or at all.
On March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of our
Elgin, Gibson City, and Grand Tower gas-fired energy centers. Additionally, on March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 12 - Subsequent Events under Part II, Item 8, of this report for additional information.
The consummation of the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers is subject to certain conditions, including the receipt of FERC approval. We expect the sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley to be completed before the closing of Ameren’s divestiture of New AER to IPH, which is expected to occur in the fourth quarter of 2013 and is a condition to IPH’s obligation to complete the divestiture. If FERC approval is not obtained, we would be required to return the $100 million initial payment to Medina Valley and IPH would not be required to consummate the purchase of New AER, which could have a material adverse effect on our results of operations, financial position and liquidity.
The consummation of the New AER divestiture to IPH is subject to regulatory approvals, including FERC approval and approval of certain license transfers by the FCC. Additionally, as a condition to IPH’s obligation to complete the transaction, the Illinois Pollution Control Board must approve the transfer to IPH of AER’s variance related to the Illinois MPS. Ameren’s and IPH’s obligation to complete the transaction is also subject to other customary closing conditions, including the material accuracy of each company’s representations and warranties and the compliance, in all material respects, with each company’s covenants. The transaction agreement contains customary representations and warranties of Ameren and IPH, including representations and warranties of Ameren with respect to the business being sold. The transaction agreement also contains customary covenants of Ameren and IPH, including the covenant of Ameren that New AER, including Genco, will be operated in the ordinary course prior to the closing.
We could recognize long-lived asset impairment charges related to our energy centers.
After the impairment of the Elgin energy center in the fourth quarter of 2012, we believed the carrying value of our energy centers exceeded their realizable fair value under current market conditions by an amount significantly in excess of $1 billion. However, under the applicable accounting guidance, an asset is not deemed impaired, and no impairment loss is recognized, unless the asset’s carrying value exceeds the estimated undiscounted future cash flows, even if the carrying value of the asset exceeds estimated fair value. We will continue to monitor the market price for power and the related impact on electric margins and other events or changes in circumstances that indicate that the carrying value of our energy centers may not be recoverable as compared to our undiscounted cash flows. We could recognize additional, material long-lived asset impairment charges in the future as a result of factors outside our control, such as changes in power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of our energy centers, and also as a result of factors that may be within our control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball, or sell our energy centers.
In 2013, we expect to record an after-tax charge to earnings estimated to be in the range of $125 million to reflect the expected losses on the sale of the Elgin, Gibson City and Grand Tower gas-fired energy centers.
We may not have access to sufficient capital in the amounts and at the times needed.
Under the provisions of our indenture, we may not borrow additional funds from external, third-party sources if our interest coverage ratio is less than a specified minimum or if our leverage ratio is greater than a specified maximum. During the first quarter of 2013, our interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and we
expect the ratio to remain less than this minimum level through at least 2015. As a result, our ability to borrow additional funds from external, third-party sources is restricted. The inability to raise debt or equity capital on favorable terms, or at all, could negatively affect our ability to maintain and to expand our business. Any adverse change in our or Ameren’s credit ratings may further reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power and natural gas supply, among other things, which could have a material adverse effect on our results of operations, financial position, and liquidity. In addition, borrowings from Ameren’s non-state-regulated subsidiary money pool are subject to Ameren’s control and any borrowings are dependent on consideration by Ameren of the facts and circumstances existing at the time of the borrowing request. We have significant debt maturities beginning in 2018.
Our energy centers must compete for the sale of energy and capacity, which exposes us to price risks.
Our energy centers compete for the sale of energy and capacity in the competitive energy markets.
To the extent that electricity generated by these energy centers is not under a fixed-price contract to be sold, our revenues and results of operations generally depend on the prices that can be obtained for energy and capacity in Illinois and adjacent markets by Marketing Company.
Market prices for energy and capacity may fluctuate substantially over both the short and long term. For example, market prices for power have decreased over the past several years. Demand for electricity and fuel can fluctuate dramatically, creating periods of substantial undersupply or oversupply. During periods of oversupply, prices might be depressed. Also, at times legislators or regulators with jurisdiction over wholesale and retail energy commodity and transportation rates may impose price limitations, bidding rules, and other mechanisms to address volatility and other issues in these markets.
For power products sold in advance, contract prices are influenced both by market conditions and by contract terms such as damage provisions, credit support requirements, and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Marketing Company’s contract portfolio may have average contract prices greater than or less than current market prices, including at the expiration of the contracts, which could affect our results of operations, financial condition and liquidity.
Any unhedged forecasted generation will be exposed to market prices at the time of sale. As a result, any new physical or financial power sales may be at price levels lower than previously experienced and lower than the value of existing hedged sales. Among the factors that could influence such prices (all of which are beyond our control to a significant degree) are:
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current and future delivered market prices for natural gas, coal, and related transportation costs;
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current and forward prices for the sale of electricity;
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current and future prices for emission allowances that may be required to operate the fossil-fuel-fired electric energy centers in compliance with environmental laws and permits;
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the extent of additional supplies of electric energy from current competitors or new market entrants;
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the regulatory and market structures developed for evolving Midwest energy markets, including a capacity market in MISO;
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changes enacted by the Illinois legislature, the ICC, the IPA, or other government agencies with respect to power procurement procedures;
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the potential for reregulation of generation in some states;
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future pricing for, and availability of, services on transmission systems, and the effect of RTOs and export energy transmission constraints, which could limit our ability to sell energy in our markets;
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the growth rate or decline in electricity usage as a result of population changes, regional economic conditions, and the implementation of energy-efficiency and conservation programs;
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climate conditions in the Midwest market and major natural disasters; and
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environmental laws and regulations or delays in their effective dates.
Our energy risk management strategies may not be effective in managing fuel and electricity procurement and pricing risks, which could result in unanticipated liabilities or increased volatility in our earnings and cash flows.
We are exposed to changes in market prices for natural gas, fuel, power, emission allowances, and transmission congestion. Prices for natural gas, fuel, power, and emission allowances may fluctuate substantially over relatively short periods of time, and at other times exhibit sustained increases or decreases, and expose us to commodity price risk. We use short-term and long-term purchase and sales contracts in addition to derivatives such as forward contracts, futures contracts, options, and swaps to manage these risks. We attempt to manage our risk associated with these activities through enforcement of established risk limits and risk management procedures. We cannot ensure that these strategies will be successful in managing our pricing risk or that they will not result in net liabilities because of future volatility in these markets.
Through Marketing Company, we routinely enter into contracts to hedge our exposure to the risks of demand and changes in commodity prices. However, Marketing Company does not hedge the entire exposure of our operations from commodity price volatility. Furthermore, our ability to hedge our exposure to commodity price volatility depends on liquid commodity markets. To the extent that commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater unhedged positions than we would prefer at a given time. To the extent that unhedged positions exist, fluctuating commodity prices can adversely affect our results of operations, financial position, and liquidity.
Energy conservation, energy efficiency efforts and other factors that reduce energy demand could adversely affect our results of operations, financial position, and liquidity.
Regulatory and legislative bodies have proposed or introduced requirements and incentives to reduce energy consumption. Conservation and energy efficiency programs are designed to reduce energy demand. Also, macroeconomic factors resulting in low economic growth or contraction could also reduce energy demand.
We are subject to various environmental laws and regulations that require significant capital expenditures. Failure to meet these standards could result in closure of facilities, increase our operating costs, adversely affect our results of operations, financial position, and liquidity, or expose us to fines and liabilities.
We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. From the beginning phases of siting and development to the operation of existing or new electric generation and transmission facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species, and other protected wildlife, and archaeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing, or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.
We are also subject to liability under environmental laws that address the remediation of environmental contamination of property now or formerly owned by us or by our predecessors, as well as property contaminated by hazardous substances that we generated. Additionally, private individuals may seek to enforce environmental laws and regulations against us and could allege injury from exposure to hazardous materials.
In addition to existing laws and regulations, including the Illinois MPS, the EPA is developing numerous new environmental regulations that will have a significant impact on electricity generators. These regulations could be particularly burdensome for certain companies, including us, that operate coal-fired energy centers. These new regulations may be litigated, so the timing of their ultimate implementation is uncertain, as evidenced by the stay and remand of the CSAPR.
We are also subject to risks in connection with changing or conflicting interpretations of existing laws and regulations. The EPA is engaged in an enforcement initiative to determine whether coal-fired energy centers failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the energy centers implemented modifications. In August 2012, Genco received a Notice of Violation from the EPA alleging violations of permitting requirements including Title V of the
Clean Air Act. The EPA contends that projects performed in 1997, 2006, and 2007 at the Newton energy center violated federal laws. We are unable to predict the outcome of this matter and whether the EPA will address this Notice of Violation administratively or through litigation.
We have incurred and expect to incur significant costs related to environmental compliance and site remediation. New environmental regulations, revised environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation could result in a significant increase in capital expenditures and operating costs, decreased revenues, increased financing requirements, penalties, fines, or closure of facilities. Actions required to ensure that our facilities and operations are in compliance with environmental laws and regulations could be prohibitively expensive. As a result, environmental regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of plant assets. We are unable to predict the ultimate impact of these matters on our results of operations, financial position, and liquidity.
Future limits on greenhouse gas emissions would probably require us to incur significant increases in capital expenditures and operating costs, which, if excessive, could result in the closures of coal-fired energy centers, impairment of assets, or otherwise adversely affect our results of operations, financial position, and liquidity.
State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions and to address global climate change. Impacts from any climate change legislation or regulation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. Our emissions of greenhouse gases vary among our energy centers, but coal-fired energy centers are significant sources of CO2.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would probably result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force us to close some coal-fired energy centers earlier than planned, which could lead to possible impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on our results of operations, financial position, and liquidity.
The construction of, and capital improvements to, our energy centers involve substantial risks. These risks include escalating costs, unsatisfactory performance by the projects when completed, the inability to complete projects as
scheduled, and the inability to earn a reasonable return on invested capital, any of which could result in higher costs and the closure of facilities.
We expect to incur significant capital expenditures to comply with existing and known environmental regulations. We estimate we will incur up to $400 million of capital expenditures during the period 2013 through 2017. These expenses include construction expenditures, capitalized interest, and capital expenditures for compliance with environmental standards. The recoverability of amounts expended will depend upon market prices for capacity and energy.
Our ability to complete construction projects successfully, and within projected estimates, is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise and escalating costs for materials, labor, and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors who do not perform as required under their contracts, changes in the scope and timing of projects, the inability to raise capital on favorable terms, or other events beyond our control that could occur may materially affect the schedule, cost, and performance of these projects. With respect to capital expenditures for pollution control equipment, there is a risk that energy centers will not be permitted to continue to operate if pollution control equipment is not installed by prescribed deadlines or does not perform as expected. Should any such pollution control equipment not be installed on time or perform as expected, we could be subject to additional costs and to the loss of our investment in the project or facility. All of these risks may adversely affect our results of operations, financial position, and liquidity.
Our counterparties may not meet their obligations to us or Marketing Company, and Ameren affiliates may not meet their obligations to each other.
We are exposed to the risk that counterparties to various arrangements who owe us money, energy, coal, or other commodities or services will not be able or willing to perform their obligations. Should the counterparties to commodity arrangements fail to perform, we might be forced to replace or to sell the underlying commitment at then-current market prices.
We have obligations to other Ameren companies and other Ameren companies have obligations to us, as a result of transactions involving energy, coal, other commodities and services, borrowing from the money pools, and as a result of hedging transactions. If one of these other Ameren companies fails to perform under any of these arrangements, we might incur losses. Our results of operations, financial position, and liquidity could be adversely affected, resulting in our inability to meet our obligations, including to unrelated third parties.
Increasing costs associated with our participation in defined benefit retirement and postretirement plans, health care plans, and other employee benefits could adversely affect our results of operations, financial position, and liquidity.
Through our involvement in the Ameren and EEI plans, our employees participate in defined benefit retirement and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates, and other actuarial matters have a significant impact on our earnings and funding requirements. We expect to fund our participation in Ameren's pension plan and EEI's pension plan at a level equal to the greater of the pension expense or the legally required minimum contribution. In 2013, we expect to make contributions of $4 million and $6 million to Ameren's pension plan and EEI's pension plan, respectively. In the aggregate, we expect to make contributions of $43 million over the next five years, with $24 million being targeted to the EEI pension plan. These amounts are estimates. They may change with actual investment performance, changes in interest rates, changes in our assumptions, changes in government regulations, any voluntary contributions, or based on Ameren's divestiture of New AER. See Note 12 - Subsequent Events under Part II, Item 8, of the accompanying financial statements.
In addition to our costs under the Ameren and EEI pension plans, the costs of providing health care benefits to our employees and retirees have increased in recent years. We believe that our employee benefit costs, including costs of health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with defined benefit retirement plans, health care plans, and other employee benefits could increase our financing needs and otherwise materially adversely affect our results of operations, financial position, and liquidity.
Our electric generation and transmission facilities are subject to operational risks that could adversely affect our results of operations, financial position, and liquidity.
Our financial performance depends on the successful operation of our electric generation and transmission facilities. Operation of electric generation and transmission facilities involves many risks, including:
•
facility shutdowns due to operator error or a failure of equipment or processes;
•
longer-than-anticipated maintenance outages;
•
older generating equipment may require significant expenditures to keep it operating at peak efficiency;
•
disruptions in the delivery of fuel or lack of adequate inventories;
•
lack of water, through low river levels or other causes, required for cooling plant operations;
•
labor disputes;
•
inability to comply with regulatory or permit requirements, including those relating to environmental contamination;
•
handling and storage of fossil-fuel combustion byproducts, such as CCR;
•
unusual or adverse weather conditions, including severe storms, droughts, floods and tornadoes;
•
a workplace accident that might result in injury or loss of life, extensive property damage, or environmental damage;
•
cybersecurity risk, including loss of operational control of our energy centers and our electric transmission systems and/or loss of data, and intellectual property through insider or outsider actions;
•
catastrophic events such as fires, explosions, pandemic health events, or other similar occurrences;
•
limitations on amounts of insurance available to cover losses that might arise in connection with operating our electric generation and transmission facilities; and
•
other unanticipated operations and maintenance expenses and liabilities.
Our facilities are considered critical energy infrastructure and may therefore be targets of acts of terrorism.
Like other electric generators, our energy centers, fuel storage facilities, and transmission facilities may be targets of terrorist activities, including cybersecurity attacks, which could result in disruption of our ability to produce some portion of our energy products. Any such disruption could result in a significant decrease in revenues or significant additional costs for repair, which could adversely affect our results of operations, financial position, and liquidity.
We are subject to federal regulatory compliance and proceedings, which increase our risk of regulatory penalties and other sanctions.
The Energy Policy Act of 2005 increased FERC’s civil penalty authority for violation of FERC statutes, rules, and orders, including FERC Reliability Standards. FERC can impose penalties of up to $1 million per violation per day. Under the Energy Policy Act of 2005, as an owner and operator of bulk power transmission systems and electric energy centers, we are subject to mandatory NERC reliability standards, including cybersecurity standards. Compliance with these mandatory reliability standards may subject us to higher operating costs and may result in increased capital expenditures. If we were found not to be in compliance with these mandatory reliability standards or other FERC statutes, rules and orders, we could incur substantial monetary penalties and other sanctions, which could adversely affect our results of operations, financial position, and liquidity.
Failure to retain and attract key officers and other skilled professional and technical employees could adversely affect on our operations.
Our business depends upon our ability to employ and retain key officers and other skilled professional and technical employees. A significant portion of our workforce is nearing retirement, including many employees with specialized skills such as maintaining, servicing and operating our energy centers.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2.PROPERTIES
For information on our principal properties, see the energy center table below. See also Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report for a discussion of planned additions, replacements or transfers. See also Note 5 - Long-term Debt, Note 10 - Commitments and Contingencies, and Note 12 Subsequent Events under Part II, Item 8, of this report.
The following table shows what the capability of our energy centers is anticipated to be at the time of our expected 2013 peak summer electrical demand:
(a)
Net kilowatt capability is the generating capacity available for dispatch from the energy center into the electric transmission grid.
(b)
Genco owns an 80% interest in EEI. This table reflects the full capability of EEI’s facilities.
(c)
On March 14, 2013, we exercised our option under an amended put option agreement with Medina Valley to sell the Elgin, Gibson City and Grand Tower gas-fired energy centers. See Note 12 - Subsequent Events under Part II, Item 8, of this report for additional information.
(d)
This CT has the capability to operate on either oil or natural gas (dual fuel).
EEI owns 42 miles of transmission lines as of December 31, 2012.
With only a few exceptions, we have fee title to all principal energy centers and other units of property material to the operation of our business, and to the real property on which such facilities are located (subject to certain permitted liens and judgment liens).
ITEM 3.
ITEM 3.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. Material legal and administrative proceedings, which are discussed in Note 10 - Commitments and Contingencies and Note 12 - Subsequent Events under Part II, Item 8, of this report and incorporated herein by reference, include the following:
•
the EPA’s Clean Air Act-related NSR investigations and the Notice of Violation for alleged permitting violations;
•
litigation alleging that the CO2 emissions from several industrial companies, including CO2 emissions from our energy centers, created atmospheric conditions that intensified Hurricane Katrina;
•
our challenge before the Informal Conference Board of the Illinois Department of Revenue regarding the State’s position that EEI did not qualify for manufacturing tax exemptions for 2010 transactions;
•
the request for FERC and FCC approvals, as well as the Illinois Pollution Control Board’s transfer of AER’s variance relating to the Illinois MPS, in connection with Ameren’s divestiture of New AER to IPH; and
•
our request for FERC approval of our transfer of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley.
ITEM 4.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
There is no established trading market for our common stock. As of February 28, 2013, our parent, Ameren Energy Resources Company, LLC, owned all of our outstanding common stock.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
(a)
Includes “Impairment and other charges” of $70 million, $35 million and $170 million recorded during the years ended December 31, 2012, 2011, and 2010, respectively. For additional information, see Note 11 - Impairment and Other Charges under Part II, Item 8, of this report.
ITEM 7.
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
General
We are headquartered in Collinsville, Illinois and were incorporated in Illinois in March 2000. We own and operate a merchant generation business in Illinois. Much of our business was formerly owned and operated by CIPS. In 2000, we acquired from CIPS, at net book value, its coal-fired energy centers. Since then, we have constructed or purchased from other affiliates natural gas-fired energy centers. We have an 80% ownership interest in EEI that AER transferred to us in 2010, at net book value. We consolidate EEI for financial reporting purposes. EEI operates merchant electric generation facilities and FERC regulated transmission facilities in Illinois. We also consolidate our wholly owned subsidiary, Coffeen and Western Railroad Company, for financial reporting purposes.
In December 2012, Ameren determined that it intended to, and it was probable that it would, exit its merchant generation business, of which we are a part. Based on the expectation of reduced financial support from Ameren, together with existing power market conditions and cash flow requirements, we estimated it was more likely than not that we would sell the Elgin energy center for liquidity purposes within two years. This change in assumption resulted in a noncash long-lived asset impairment charge during the fourth quarter of 2012. See Note 11 - Impairment and Other Charges under Part II, Item 8, of this report for additional information. Our long-lived assets were not classified as held-for-sale under authoritative accounting guidance as all criteria to qualify for that presentation were not
met as of December 31, 2012. Specifically, we did not consider it probable that a disposition of an energy center would occur within one year.
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Immediately prior to Ameren’s entry into the transaction agreement with IPH on March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. Both March 2013 transactions are regarded as subsequent events to the accompanying December 31, 2012 consolidated financial statements. See Note 12 - Subsequent Events under Part II, Item 8, of this report for additional information.
Genco (parent) has a PSA with Marketing Company, whereby it agreed to sell and Marketing Company agreed to purchase all of the capacity and energy available from its generation fleet. Marketing Company entered into a similar PSA with AERG. Under these PSAs, revenues allocated between Genco and AERG are based on reimbursable expenses and generation of each entity. Each PSA will continue through December 31, 2022, and from year to year thereafter unless either party to the respective PSA elects to terminate the PSA by providing the other party with no less than six months advance written notice.
EEI has a PSA with Marketing Company, whereby EEI agreed to sell and Marketing Company agreed to purchase all of the capacity and energy available from EEI’s generation fleet. The price that Marketing Company pays for capacity is set annually based upon prevailing market prices. Marketing Company pays spot market prices for the associated energy. In addition, EEI may at times purchase energy from Marketing Company to fulfill obligations to a nonaffiliated party. This PSA will continue through May 31, 2016, unless either party elects to terminate the PSA by providing the other party with no less than four years advance written notice or five days’ written notice in the event of a default, unless the default is cured within 30 business days.
See Note 2 - Related Party Transactions under Part II, Item 8, of this report for additional information on the power supply agreements.
RESULTS OF OPERATIONS
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. Ultimately, our sales are subject to market conditions for power. We principally use coal and natural gas for fuel in our operations. The prices for these commodities can fluctuate significantly because of the global economic and political environment, weather, supply and demand, and many other factors. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our energy centers, operations and maintenance costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.
Earnings Summary
Net loss attributable to Genco was $33 million and $39 million for 2012 and 2010, respectively. Net income attributable to Genco was $44 million for 2011.
2012 versus 2011
Our earnings in 2012, compared with 2011, were adversely affected by reduced electric margins, which declined as a result of lower sales volumes, primarily due to lower realized prices. Another factor contributing to the net loss in 2012 was the impairment charge of $70 million, before taxes, associated with the Elgin energy center. Earnings in 2012 benefited from a reduction in other operations and maintenance expenses and depreciation expenses as a result of the December 2011 closure of the Meredosia and Hutsonville energy centers.
2011 versus 2010
Earnings in 2011 benefited from reduced impairment and other charges. During 2010, we recorded pretax impairment charges of $170 million related to long-lived assets, goodwill, and
intangible assets. During 2011, we recorded a pretax long-lived asset impairment charge of $35 million. Additionally, interest charges decreased by $15 million, primarily due to the maturity and repayment of senior unsecured notes in 2010. Partially offsetting those benefits, electric margins decreased by $73 million as realized prices declined due to a reduction in higher-margin sales after the expiration of long-term contracts and because of lower market prices.
For additional details regarding results of operations, including explanations of Margins, Other Operations and Maintenance Expenses, Impairment and Other Charges, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income and Expenses, Interest Charges, and Income Taxes, see the major headings below.
Margins
The following table presents the favorable (unfavorable) variations for electric margins from the previous year. Electric margins are defined as electric revenues less fuel and purchased power costs. The table covers the years ended December 31, 2012, 2011, and 2010. We consider electric 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, these margins may not be a presentation defined under GAAP, and may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.
2012 versus 2011
Electric margins decreased by $145 million, or 31%, in 2012 compared with 2011. The following items had an unfavorable impact on electric margins:
•
Decreased energy center utilization, primarily due to lower spot market prices, resulting in a decline in sales volumes. In addition, an EEI sales contract in 2011 was not supplied in 2012. Both of these combined to decrease revenues by
$218 million. This decline was mitigated by a related $101 million decrease in production volume and other costs and a $54 million decrease in purchased power and other costs. Our energy centers’ average capacity factor decreased to 62%, in 2012, compared with 71%, in 2011, because of lower power prices. The equivalent availability factor decreased to 85% in 2012, compared with 86% in 2011.
•
Lower revenues allocated under the Genco (parent) PSA with Marketing Company. There was a smaller pool of money to allocate because of lower market prices. We were allocated a lower percentage of revenues from the pool because of lower reimbursable expenses and lower levels of generation relative to AERG. We also experienced lower market prices associated with the EEI PSA. The combined impact of lower market prices under both power supply agreements resulted in an unfavorable price variance, which decreased revenues by $42 million.
•
3% higher fuel prices, primarily due to higher commodity costs associated with new coal supply agreements, decreased margins by $23 million.
•
Net unrealized MTM activity primarily on fuel-related contracts, decreased margins by $16 million.
2011 versus 2010
Electric margins decreased by $73 million, or 13%, in 2011 compared with 2010. The following items had an unfavorable impact on electric margins:
•
Lower revenues allocated under the Genco (parent) PSA with Marketing Company. There was a smaller pool of money to allocate because of reductions in higher-margin sales, after the expiration of long-term contracts, and because of lower market prices. However, in accordance with the Genco (parent) PSA, we were allocated a higher percentage of revenues from the pool because of higher reimbursable expenses and greater levels of generation relative to AERG. We also experienced lower market prices associated with the EEI PSA. The combined impact of lower market prices under both power supply agreements resulted in an unfavorable price variance, which reduced revenues by $58 million. The decrease in revenues was mitigated by a favorable settlement of a contract dispute with a large customer in 2011.
•
5% higher fuel prices, primarily due to higher commodity and transportation costs associated with escalations in existing transportation agreements and new commodity supply agreements, which decreased margins by $11 million.
•
Net unrealized MTM activity on fuel-related transactions, primarily associated with financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts, and on nonqualifying power hedges, which decreased margins by $10 million.
The following items had a favorable impact on Genco’s electric margin in 2011 compared with 2010:
•
Lower average prices on power purchased to supply a large customer, which increased margins by $6 million.
•
Energy center utilization in 2011 was comparable with 2010. Production volume increased electric revenues by $2 million, which was offset by a $2 million increase in production volume and other costs. Our energy centers’ average capacity factor remained unchanged at 71% in 2011 and 2010, but the equivalent availability factor decreased to 86% in 2011, compared with 88% in 2010.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses decreased by $13 million in 2012 compared with 2011, primarily because maintenance costs decreased by $25 million as a result of the December 2011 closure of the Meredosia and Hutsonville energy centers and fewer outages at our other energy centers. Partially offsetting decreased maintenance costs were reduced net gains from property sales of $11 million between years and charges for canceled projects in 2012 of $4 million.
Other operations and maintenance expenses decreased by $12 million in 2011 compared with 2010, primarily because of a $7 million increase in gains on property sales.
Impairment and Other Charges
The following table summarizes impairment and other charges for the years ended December 31, 2012, 2011, and 2010:
See Note 1 - Summary of Significant Accounting Policies, Note 2 - Related Party Transactions, Note 11 - Impairment and Other Charges and Note 12 - Subsequent Events under Part II, Item 8, of this report for additional information. The impairment charges did not result in a violation of any debt covenants or counterparty agreements.
We have experienced decreasing earnings and cash flows from operating activities over the past few years, including in 2012, as margins have declined principally as a result of weaker power prices. In addition, environmental regulations have resulted in significant investment requirements over the same time frame. During the first quarter of 2012, the observable market price for power for delivery in that year and in future years in the Midwest sharply declined below 2011 levels primarily because of declining natural gas prices and the impact of the stay of the CSAPR. As a result of this sharp decline in the market price of power and the related impact on electric margins, we decelerated the construction of two scrubbers at the Newton energy center in February 2012. The sharp decline in the market
price of power in the first quarter of 2012 and the related impact on electric margins, as well as the deceleration of construction of the Newton energy center scrubber project, caused us to evaluate, during the first quarter of 2012, whether the carrying values of our coal-fired energy centers were recoverable. The first quarter test demonstrated that the estimated undiscounted future cash flows of long-lived assets exceeded their carrying values, which resulted in no impairment during the first quarter of 2012. In this first quarter 2012 test, we assumed cash flows associated with each energy center would continue through the end of each energy center’s useful life.
Ameren, which owns our parent company, is increasingly focused on allocating its capital resources to those opportunities that it believes offer the most attractive risk-adjusted return potential, and specifically focused on growing earnings from its rate-regulated operations through investment under constructive regulatory frameworks. Ameren has sought to have us fund our operations internally and not rely on financing from Ameren. In December 2012, Ameren determined that it intended to, and it was probable that it would, exit its merchant generation business, of which we are a part, before the end of the previously estimated useful lives of that business's long-lived assets.
Ameren's December 2012 decision that it intended to, and it was probable that it would, reduce and ultimately eliminate the financial support and shared services support it provides us caused us to evaluate, during the fourth quarter of 2012, whether the carrying values of our energy centers were recoverable. Based on the expectation of reduced financial support from Ameren, together with existing power market conditions and cash flow requirements, we estimated that we would more likely than not require additional liquidity to support our operations before the put option agreement was due to expire on March 28, 2014. As a result of our expectation at that time that it was more likely than not that we would sell the Elgin energy center for liquidity purposes, the Elgin energy center's carrying value exceeded its estimated undiscounted future cash flows. Accordingly, we recorded a noncash pretax impairment charge of $70 million during the fourth quarter of 2012 to reduce the carrying value of the Elgin energy center to its estimated fair value. The estimated undiscounted cash flows for our other energy centers exceeded their carrying values and therefore were unimpaired. Under the applicable accounting guidance, if undiscounted future cash flows from these long-lived assets exceed their carrying values, the assets are deemed unimpaired, and no impairment loss is recognized, even if the carrying values of the assets exceed estimated fair values.
After the impairment of the Elgin energy center in the fourth quarter of 2012, we believed the carrying value of our energy centers exceeded their realizable fair value under current market conditions by an amount significantly in excess of $1 billion. See Note 12 - Subsequent Events under Part II, Item 8, of this report for information regarding our expected 2013 charge to earnings related to the sale to Medina Valley of the Elgin, Gibson City, and Grand Tower gas-fired energy centers. We will continue to monitor the market price for power and the related impact on electric margin, our liquidity needs, and other events or changes
in circumstances that indicate that the carrying value of our energy centers may not be recoverable as compared to their undiscounted cash flows. We could recognize additional, material long-lived asset impairment charges in the future if estimated undiscounted cash flows no longer exceed carrying values for long-lived assets. This may occur either as a result of factors outside our control, such as changes in market prices of power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of our energy centers, and also as a result of factors that may be within our control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball, or sell energy centers. As of December 31, 2012, the carrying value of long-lived assets was $2.2 billion.
Key assumptions used in the determination of estimated undiscounted cash flows of our long-lived assets tested for impairment during the first and fourth quarters of 2012 included forward price projections for energy and fuel costs, the expected life or duration of ownership of the long-lived assets, environmental compliance costs and strategies, and operating costs. Those same cash flow assumptions, along with a discount rate and a terminal year earnings multiple, were used to estimate the fair value of the Elgin energy center during the fourth quarter. These assumptions are subject to a high degree of judgment and complexity. The fair value estimate of the Elgin energy center was based on a combination of the income approach, which considers discounted cash flows, and the market approach, which considers market multiples for similar assets within the electric generation industry. For the fourth quarter 2012 long-lived asset impairment test, we used a discount rate of 11.5%, a terminal year earnings multiple of 6, and estimated the Elgin energy center's duration of ownership to be less than two years. Holding all other assumptions constant, if the discount rate had been one percentage point higher, or if the terminal year earnings multiple had been one point lower, or if the duration of ownership for the Elgin energy center was one year less than estimated, the fourth quarter 2012 impairment charge would have been $55 million higher.
Our 2012 long-lived asset impairment charge is expected to reduce 2013 depreciation expense by $3 million.
In December 2011, we ceased operations of the Meredosia and Hutsonville energy centers. As a result, we recorded noncash pretax asset impairment charges of $26 million to reduce the carrying value of the Meredosia and Hutsonville energy centers to their estimated fair values, a $4 million impairment of materials and supplies, and $4 million for severance costs.
During the third quarter of 2010, the aggregate impact of a sustained decline in market prices for electricity, industry market multiples became observable at lower levels than previously estimated, and potentially more stringent environmental regulations being enacted caused us to evaluate if the carrying values of our energy centers were recoverable. The Meredosia
energy center's carrying value exceeded its estimated undiscounted future cash flows. As a result, during 2010, we recorded a noncash pretax asset impairment charge of $64 million to reduce the carrying value of the Meredosia energy center to its estimated fair value.
Prior to 2010, we expected to use SO2 emission allowances for ongoing operations. In July 2010, the EPA issued the proposed CSAPR, which would have restricted the use of existing SO2 emission allowances. As a result, we no longer expected that all of our SO2 emission allowances would be used in operations. Therefore, during 2010, we recorded a noncash pretax impairment charge of $41 million to reduce the carrying value of SO2 emission allowances to their estimated fair value. In July 2011, the EPA issued the final CSAPR, which created new allowances for SO2 and NOx emissions and restricted the use of pre-existing SO2 and NOx allowances to the acid rain program and to the NOx budget trading program, respectively. As a result, observable market prices for existing emission allowances declined materially. We recorded a noncash pretax impairment charge of $1 million in 2011 relating to emission allowances.
During 2010, we also recorded a noncash pretax goodwill impairment charge of $65 million, which represented all of the goodwill assigned to us. The goodwill impairment recorded in 2010 was caused by a sustained decline in market prices for electricity, by industry market multiples becoming observable at lower levels than previously estimated, and by the possibility that more stringent environmental regulations would be enacted.
Depreciation and Amortization
Depreciation and amortization expenses decreased by $11 million in 2012 compared with 2011, primarily because of a change in estimates related to asset retirement obligations and the closure of the Meredosia and Hutsonville coal-fired energy centers in December 2011.
Depreciation and amortization expenses were comparable between 2011 and 2010.
Taxes Other Than Income Taxes
Taxes other than income taxes were comparable between 2012, 2011, and 2010.
Other Income and Expenses
Other income, net of expenses, was comparable between 2012, 2011, and 2010.
Interest Charges
Interest charges decreased by $11 million in 2012 compared with 2011, primarily because of increased capitalized interest due to the Newton energy center scrubber project.
Interest charges decreased by $15 million in 2011 compared with 2010, primarily because of the maturity and repayment of $200 million of senior unsecured notes in November 2010.
Income Taxes
The effective income tax rate was 42%, 42% and (125)% for 2012, 2011 and 2010, respectively.
The effective tax rate was higher in 2011 compared with 2010 primarily because of the impact of the nondeductible goodwill impairment charge on a pretax book loss in 2010, along with the increase in the Illinois statutory income tax rate in 2011, the decrease in the effective tax rate from the effect of the change in the tax treatment of retiree health care costs in 2010 on a pretax book loss and unfavorable changes in reserves for uncertain tax positions on a pretax book loss in 2010. These were offset by the impact of the investment tax credits and state tax credits on pretax book income in 2011, as compared to a pretax book loss in 2010, along with lower production activities deductions in 2011 versus 2010.
LIQUIDITY AND CAPITAL RESOURCES
Through Marketing Company, we sell power primarily through market-based contracts with wholesale and retail customers to generate operating cash flows. In December 2012, Ameren determined that it intended to, and it was probable that it would, exit its merchant generation business, of which we are a part. In consideration of this determination, Ameren began planning to reduce, and ultimately eliminate, our reliance on Ameren’s financial support and shared services support. On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 12 - Subsequent Events under Part II, Item 8, of this report for additional information. While we remain a business of Ameren, we will seek to fund our operations internally and therefore will seek not to rely on financing from Ameren. We will seek to defer or reduce capital and operating expenses, sell certain assets, and to take other actions as necessary to fund our operations internally while maintaining safe and reliable operations. Additionally, we have the potential to receive proceeds from our tax allocation agreement with Ameren through its ownership period. See Note 1 - Summary of Significant Accounting Policies under Item II, Part 8, of this report for additional information related to the tax allocation agreement. The 2010 Genco Credit Agreement was terminated in November 2012 and not replaced.
Under the provisions of our indenture, we may not borrow additional funds from external, third-party sources if our interest coverage ratio is less than a specified minimum or if our leverage ratio is greater than a specified maximum. See Note 5 - Long-term Debt under Part II, Item 8, of this report for additional information on our indenture provisions. During the first quarter of 2013, our interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and we expect the ratio to remain less than this minimum level through at least 2015. As a result, our ability to borrow additional funds from external, third-party sources is restricted. Our indenture does not restrict intercompany borrowings from Ameren's non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren's control. If an intercompany
financing need were to arise, borrowings from the non-state-regulated subsidiary money pool would be dependent on consideration by Ameren of the facts and circumstances existing at that time. Should a financing need arise, our sources of liquidity include available cash on hand, a return of money pool advances, money pool borrowings at the discretion of Ameren, or the sale of assets. On March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. See Note 12 - Subsequent Events under Part II, Item 8, of this report for additional information. Based on current projections, including the amount received related to the put option, we expect operating cash flows to approximate nonoperating cash flow requirements in 2013 and daily working capital needs to be sufficiently covered by cash on hand. Based on projections as of December 31, 2012, we estimate these financing sources are adequate to support our operations in 2013.
The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2012, 2011, and 2010:
Cash Flows from Operating Activities
2012 versus 2011
Cash from operating activities decreased in 2012 compared with 2011. Electric margins, as discussed in Results of Operations, decreased by $129 million, excluding impacts of noncash MTM transactions.
The following items partially offset the decrease in cash from electric margins during 2012, compared with 2011:
•
Accounts payable balances related to coal purchases increased $14 million, primarily due to increased purchases to support increased refined coal activity in 2012.
•
A $6 million decrease in labor expenditures and a $5 million decrease in payments to contractors, primarily due to the 2011 Meredosia and Hutsonville energy center closures.
•
The receipt of $10 million for net coal transfers to refiners under agreements that began in late 2011. The coal will be purchased back from the refiners in a subsequent period.
•
An $8 million decrease in coal inventory, primarily due to continued focus on inventory reductions, partially offset by increased coal prices.
2011 versus 2010
Cash from operating activities decreased in 2011 compared with 2010. The following items contributed to the decrease in cash from operating activities during 2011, compared with 2010:
•
Electric margins, as discussed in Result of Operations, decreased by $63 million, excluding impacts of noncash MTM transactions.
•
During 2010, we significantly reduced the volume of our coal inventory, which resulted in an estimated $43 million cash savings in excess of the smaller inventory reduction that occurred in 2011.
•
The January 2010 receipt from Marketing Company for December 2009 generation output was $16 million higher than the January 2011 receipt for December 2010 generation output. This was primarily caused by the inclusion of higher-priced sales contracts from the 2006 Illinois power procurement auction, which expired in May 2010.
•
A $9 million increase in payments associated with major outages at coal-fired energy centers, primarily because the scope of the major outages in 2011 were more extensive than the scope of the major outages performed in 2010.
•
An $8 million increase in pension plan contributions as EEI made a contribution in 2011, but made no contribution in 2010.
The following items reduced the decrease in cash from operating activities during 2011, compared with 2010:
•
Income tax refunds of $25 million in 2011, compared with income tax payments of $1 million in 2010. The 2011 refund was primarily due to an increase in accelerated depreciation deductions authorized by the economic stimulus legislation. We did not make any federal income tax payments in 2011 primarily because of accelerated deductions related to pollution control equipment, economic stimulus legislation and deductions related to the closure of Meredosia and Hutsonville energy centers.
•
A $20 million decrease in interest payments, primarily due to the redemption of senior notes in November 2010.
Pension Funding
Through our involvement in the Ameren and EEI pension plans, our employees participate in defined benefit retirement plans that cover substantially all of our employees. Ameren’s and EEI’s pension plans are funded in compliance with income tax regulations and to meet federal funding or regulatory requirements. As a result, we expect to fund our participation in Ameren's pension plan and EEI's pension plan at a level equal to the greater of the pension expense or the legally required minimum contribution. In 2013, we expect to make contributions of $4 million and $6 million to Ameren's pension plan and EEI's pension plan, respectively. In the aggregate, we expect to make contributions of $43 million over the next five years, with $24 million being targeted to the EEI pension plan. These amounts are estimates. The estimates may change with actual investment performance, changes in interest rates, changes in our assumptions, any pertinent changes in government regulations, any voluntary contributions, or based on Ameren's divestiture of New AER. See Note 12 - Subsequent Events under Part II, Item 8, of the accompanying financial statements. In 2012, we contributed $11 million to the Ameren and EEI pension plans.
See Note 6 - Retirement Benefits under Part II, Item 8, of this report for additional information.
Cash Flows from Investing Activities
2012 versus 2011
Cash used in investing activities decreased during 2012, compared 2011, principally attributable to a change in net money pool advances offset by an increase in capital expenditures and a reduction in proceeds related to sales of properties. During 2012, capital expenditures exceeded net cash provided by operating activities by $36 million. The cash shortfall was funded by repayments of advances previously paid to Ameren’s money pool. In 2011, net cash provided by operating activities exceeded capital expenditures by $74 million, which allowed us to contribute $49 million to the money pool. In 2012, capital expenditures increased by $34 million primarily because of increased expenditures related to the scrubber project at the Newton energy center, which more than offset a reduction in maintenance and upgrade project expenditures due to the timing of energy center outages. In 2012, cash flows from investing activities benefited from the sales of assets for proceeds of $6 million, which resulted in a net $1 million pretax gain. In 2011, cash flows from investing activities benefited from property sale proceeds, principally attributable to $45 million received from the sale of our interest in the Columbia CT facility.
2011 versus 2010
Cash used in investing activities increased by $112 million during 2011, compared with 2010. Net cash used for capital expenditures increased by $46 million primarily as a result of increased spending for energy center scrubber projects and boiler projects. The Coffeen energy center scrubber project was completed in February 2010, and construction began in April 2011 on the Newton energy center scrubber project. In 2011, cash flows from investing activities benefited from the proceeds of property sales, principally attributed to $45 million of proceeds received from the sale of our remaining interest in our Columbia CT facility. In 2010, cash flows from investing activities benefited from the proceeds received from the sale of 25% of our Columbia CT facility. During 2011, cash provided by sales of properties enabled us to contribute net money pool advances of $49 million. During 2010, we received $48 million in net repayment of money pool advances.
Capital Expenditures
Capital expenditures for the years ended December 31, 2012, 2011, and 2010 were $175 million, $141 million, and $95 million, respectively. Capital expenditures principally consisted of energy center upgrades to comply with environmental regulations. In 2012, 2011, and 2010 respectively, we spent $141 million, $75 million and $29 million toward scrubber projects. Other capital expenditures were made principally to fund various energy center upgrades.
The following table estimates the capital expenditures that will be incurred from 2013 through 2017. Estimated capital expenditures are primarily for compliance with known and existing environmental regulations and upgrades to existing coal and natural gas-fired energy centers discussed below. See Outlook and also Note 10 - Commitments and Contingencies under Part II, Item 8, of this report for further discussion of the impact of declining power prices on our business.
We continually review our generation portfolio and expected power needs. As a result, we could modify our plan for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other things. Any changes that we may plan to make for future generation needs could result in significant capital expenditures or losses being incurred, which could be material.
We will incur significant costs in future years to comply with existing and known federal and state regulations including those requiring the reduction of SO2, NOx, and mercury emissions from coal-fired energy centers.
See Note 10 - Commitments and Contingencies under Part II, Item 8, of this report for a discussion of existing environmental laws and regulations that affect, or may affect, our facilities and capital costs to comply with such laws and regulations, as well as our assessment of the potential impacts of the EPA’s proposed regulation of CCR and cooling water intake structures, the MATS, the stayed CSAPR, and the finalized MATS, as of December 31, 2012.
Cash Flows from Financing Activities
2012 versus 2011
Net cash used in financing activities decreased during 2012, compared with 2011. In 2012, we met our working capital and investing requirements without utilizing financing. In 2011, we received a $28 million capital contribution from AER, our parent, associated with a tax allocation agreement that benefited cash flows from financing activities and we utilized surplus net cash from operating activities to repay $100 million of short-term borrowing obligations.
2011 versus 2010
Net cash used in financing activities decreased by $203 million in 2011 compared with 2010. During 2011, cash flow from operating activities of $215 million exceeded our capital expenditures of $141 million. Additionally, we received a capital contribution from Ameren associated with a tax allocation agreement that benefited 2011 cash flows from financing
activities. We used this cash to reduce our reliance on credit facility borrowings. In 2010, we repaid at maturity $200 million of our 8.35% senior notes at maturity and repaid a net $176 million of intercompany note borrowings. These 2010 cash outlays were offset, in part, by credit facility borrowings.
Short-term Borrowings and Liquidity
Our liquidity needs are typically supported through the use of available cash on hand, a return of money pool advances, or money pool borrowings at the discretion of Ameren. The 2010 Genco Credit Agreement was terminated on November 14, 2012 and was not renewed. See Note 4 - Short-Term Debt and Liquidity under Part II, Item 8, of this report for additional information on short-term borrowing activity, and relevant interest rates, and borrowings under Ameren’s money pool arrangement.
Ameren’s credit agreements were available for use, subject to applicable regulatory short-term borrowing authorizations, through direct short-term borrowings from Ameren and through a money pool agreement. Ameren has money pool agreements with and among its subsidiaries to coordinate and to provide for certain short-term cash and working capital requirements. Ameren Services is responsible for operation and administration of the money pool agreements. See Note 4 - Short-Term Debt and Liquidity under Part II, Item 8, of this report for a detailed explanation of the money pool arrangement.
Genco has unlimited long and short-term debt issuance authorization from FERC. EEI has unlimited short-term debt authorization from FERC.
Long-term Debt and Equity
For the years ended 2012 and 2011, there were no issuances of common stock, and no issuances, redemptions, repurchases, or maturities of long-term debt. In November 2010, our $200 million Series D 8.35% Senior notes matured and were retired. For additional information see Note 5 - Long-term Debt under Part II, Item 8, of this report.
Indebtedness Provisions and Other Covenants
See Note 5 - Long-term Debt under Part II, Item 8, of this report for a discussion of covenants and provisions contained in our term loan agreements and in our indenture.
At December 31, 2012, we were in compliance with the provisions and covenants contained within our indenture.
Operating results and operating cash flows are significantly affected by changes in market prices for power, which have significantly decreased over the past few years. Under the provisions of our indenture, we may not borrow additional funds from external, third-party sources if our interest coverage ratio is
less than a specified minimum or if our leverage ratio is greater than a specified maximum. During the first quarter of 2013, our interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and we expect the ratio to remain less than this minimum level through at least 2015. As a result, our ability to borrow additional funds from external, third-party sources is restricted. Our indenture does not restrict intercompany borrowings from Ameren’s non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren’s control. If an intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool would be dependent on consideration by Ameren of the facts and circumstances existing at that time. We will seek to fund operations internally and therefore seek not to rely on financing from Ameren.
Should a financing need arise, our sources of liquidity include available cash on hand, a return of money pool advances, money pool borrowings at the discretion of Ameren, or the sale of assets. On March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC regulatory approval. See Note 12 - Subsequent Events under Part II, Item 8, for additional information. Based on current projections, including the amount received related to exercising the put option, we expect operating cash flows to approximate nonoperating cash flow requirements in 2013 and daily working capital needs to be sufficiently covered by cash on hand. See Note 2 - Related Party Transactions under Part II, Item 8, of this report for additional information regarding the put option agreement.
Dividends
Our indenture includes restrictions that prohibit payments of dividends on our common stock. Specifically, dividends cannot be paid unless the actual interest coverage ratio for the most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. Based on projections as of December 31, 2012, of operating results and cash flows in 2013 and 2014, we did not believe that we would achieve the minimum interest coverage ratio necessary to pay dividends on our common stock for each of the subsequent four six-month periods ending June 30, 2013, December 31, 2013, June 30, 2014, or December 31, 2014. As a result, we were restricted from paying dividends as of December 31, 2012, and we expect to be unable to pay dividends in 2013, 2014, and 2015. See Note 5 - Long-term Debt under Part II, Item 8, of this report for additional information on indenture provisions. No dividends were paid to our parent, AER, in 2012, 2011, or 2010.
Contractual Obligations
The following table presents our contractual obligations as of December 31, 2012. See Note 6 - Retirement Benefits under Part II, Item 8, of this report for information regarding expected minimum funding levels for our pension plans. These expected pension funding amounts are not included in the table below. In addition, routine short-term purchase order commitments are not included.
(a)
Excludes unamortized discount and premium of $1 million.
(b)
See Other Obligations within Note 10 - Commitments and Contingencies under Part II, Item 8, of this report, for discussion of items included herein.
(c)
See Note 12 - Subsequent Events under Part II, Item 8, of this report for a discussion of the impact of the divestiture of New AER to IPH on our contractual obligations.
As of December 31, 2012, we had $6 million of unrecognized tax benefits under the authoritative accounting guidance for uncertain tax positions. It is reasonably possible to expect that the settlement of an unrecognized tax benefit will result in an underpayment or overpayment of tax and related interest. However, there is a high degree of uncertainty with respect to the timing of cash payments or receipts associated with unrecognized tax benefits. The amount and timing of certain payments or receipts is not reliably estimable or determinable at this time. See Note 7 - Income Taxes under Part II, Item 8, of this report for information regarding our unrecognized tax benefits and related liabilities for interest expense.
Off-Balance-Sheet Arrangements
At December 31, 2012, we did not have any off-balance-sheet financing arrangements other than operating leases entered into in the ordinary course of business. We do not expect to engage in any significant off-balance-sheet financing arrangements in the near future.
Credit Ratings
Credit ratings affect our liquidity, our access to the capital markets and credit markets, and collateral posting requirements under commodity contracts.
The following table presents the principal credit ratings by Moody’s, S&P, and Fitch effective on the date of this report:
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.
Collateral Postings
Any adverse change in our credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power, and natural gas supply, among other things, resulting in a negative impact on earnings. As of December 31, 2012, we had no cash collateral postings or prepayments with external parties, including postings related to exchange-traded contracts, nor did we hold cash collateral from external counterparties. The sub-investment-grade issuer and senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at December 31, 2012, could have resulted in us being required to post additional collateral or other assurances for certain trade obligations amounting to $38 million.
Changes in commodity prices could trigger additional collateral postings and prepayments at current credit ratings. If market prices were 15% higher than December 31, 2012, levels in the next 12 months and 20% higher thereafter through the end of the term of the commodity contracts, then we could be required to post additional collateral or other assurances for certain trade obligations up to $36 million. If market prices were 15% lower than December 31, 2012, levels in the next 12 months and 20% lower thereafter through the end of the term of the commodity contracts, then we could be required to post additional collateral or other assurances for certain trade obligations up to $47 million.
OUTLOOK
Below are some key trends, events, and uncertainties that are reasonably likely to affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for 2013 and beyond.
•
On March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC
approval. Additionally, on March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 12 - Subsequent Events under Part II, Item 8, of this report for additional information. In 2013, we expect to record an after-tax charge to earnings in the range of $125 million to reflect the expected loss on the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers. In 2012, under the terms of the Genco PSA with Marketing Company, we were allocated revenues attributable to the Elgin, Gibson City, and Grand Tower gas-fired energy centers that approximated their operating expenses, excluding Elgin's long-lived asset impairment charge. However, the sale of these energy centers to Medina Valley will impact the allocation of revenues between us and AERG going forward and could result in a material change to our results of operations depending on our reimbursable costs compared to AERG's reimbursable costs, our generation level compared to AERG's generation level, and Marketing Company's realized revenues.
•
See Note 11 - Impairment and Other Charges under Part II, Item 8, of this report for information regarding our December 2012 impairment charge relating to the Elgin energy center. We estimate the reduction to our net property and plant carrying value caused by the December 2012 impairment will result in a $3 million reduction in annual depreciation expense.
•
After the impairment of the Elgin energy center in the fourth quarter of 2012, we believed the carrying value of our energy centers exceeded their realizable fair value under current market conditions by an amount significantly in excess of $1 billion. We could recognize additional, material long-lived asset impairment charges in the future if estimated undiscounted cash flows no longer exceed carrying values for long-lived assets. This may occur as a result of factors outside our control, such as changes in market prices of power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of our energy centers, and also as a result of factors that may be within our control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell energy centers. As of December 31, 2012, the carrying value of long-lived assets was $2.2 billion. Impairments could result in lower revenues under certain cost-based contracts.
•
As of December 31, 2012, we expected to have available generation from our coal-fired energy centers of 24 million megawatthours in any given year. However, based on currently expected power prices, we expect to generate approximately 20.5 million megawatthours in 2013, with approximately 94% of this generation expected to be from coal-fired energy centers.
•
Power prices in the Midwest affect the revenues and cash flows we can realize, through Marketing Company, by marketing power into the wholesale and retail markets. We are adversely affected by the declining market price of power for any unhedged generation. Market prices for power
have decreased over the past several years, especially sharply during the first quarter of 2012.
•
As of December 31, 2012, Marketing Company had hedged approximately 19 million megawatthours of our expected generation for 2013, at an average price of $36 per megawatthour. For 2014, Marketing Company had hedged approximately 10.5 million megawatthours of our forecasted generation sales at an average price of $38 per megawatthour. For 2015, Marketing Company had hedged approximately 5 million megawatthours of our forecasted generation sales at an average price of $40 per megawatthour. Any unhedged forecasted generation will be exposed to market prices at the time of sale. As a result, any new physical or financial power sales may be at price levels lower than previously experienced and lower than the value of existing hedged sales.
•
To further reduce cash flow volatility, we seek to hedge fuel costs consistent with power sales. As of December 31, 2012, for 2013 we had hedged fuel costs for approximately 19 million megawatthours of coal and up to 19 million megawatthours of base transportation at about $23 per megawatthour. For 2014, we had hedged fuel costs for approximately 9 million megawatthours of coal and up to 14 million megawatthours of base transportation at about $24 per megawatthour. For 2015, we had hedged fuel costs for approximately 4 million megawatthours of coal and up to 14 million megawatthours of base transportation at about $26 per megawatthour. See Item 7A
ITEM 7A.
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 nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices, and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset or index. The following discussion of our risk management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the forward-looking statements. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks, principally business, legal, and operational risks, are not part of the following discussion.
Our risk management objective is to optimize our physical generating assets and to pursue market opportunities within prudent risk parameters. Our risk management policies are set by a risk management steering committee, which is composed of senior-level Ameren officers.
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated with:
•
long-term and short-term variable-rate debt;
•
fixed-rate debt; and
•
defined pension and postretirement benefit plans.
We manage our interest rate exposure by controlling the amount of debt instruments within our total capitalization portfolio and by monitoring the effects of market changes on interest rates. For defined pension and postretirement benefit plans, EEI controls the duration and the portfolio mix of its plan assets.
At December 31, 2012, we had no variable-rate debt outstanding.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties should fail to perform as contracted. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction. See Note 8 - Derivative Financial Instruments under Part II, Item 8, of this report for information on the potential loss on counterparty exposure as of December 31, 2012.
Our physical and financial instruments are subject to credit risk consisting of accounts receivable and executory contracts with market risk exposures. Our revenues are primarily derived from the sales of electricity to Marketing Company as described in Note 2 - Related Party Transactions, under Part II, Item 8
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of Ameren Energy Generating Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Ameren Energy Generating Company and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
April 1, 2013
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(In millions)
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
(In millions)
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
We are a non-rate-regulated electric generation subsidiary of AER, which is a subsidiary of Ameren Corporation. Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries, like us, are separate, independent legal entities with separate businesses, assets, and liabilities.
We are headquartered in Collinsville, Illinois and were incorporated in Illinois in March 2000. We own and operate a merchant generation business in Illinois. Much of our business was formerly owned and operated by CIPS. In 2000, we acquired from CIPS, at net book value, its coal-fired energy centers. Since then, we have constructed or purchased from other affiliates natural gas-fired energy centers. We have an 80% ownership interest in EEI that AER transferred to us in 2010, at net book value. We consolidate EEI for financial reporting purposes. EEI operates merchant electric generation facilities and FERC regulated transmission facilities in Illinois. We also consolidate our wholly owned subsidiary, Coffeen and Western Railroad Company, for financial reporting purposes. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
In December 2012, Ameren determined that it intended to, and it was probable that it would, exit its merchant generation business, of which we are a part. Based on the expectation of reduced financial support from Ameren, together with existing power market conditions and cash flow requirements, we estimated, at that time, it was more likely than not that we would sell the Elgin energy center for liquidity purposes within two years. This change in assumption resulted in a noncash long-lived impairment charge during the fourth quarter of 2012. See Note 11 - Impairment and Other Charges. Our long-lived assets have not been classified as held-for-sale under authoritative accounting guidance as all criteria to qualify for that presentation were not met as of December 31, 2012. Specifically, we did not consider it probable that a disposition of an energy center would occur within one year.
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Immediately prior to Ameren’s entry into the transaction agreement with IPH, on March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. Both March 2013 transactions are regarded as subsequent events to the accompanying December 31, 2012 consolidated financial statements. See Note 12 - Subsequent Events for additional information.
Our accounting policies conform to GAAP. Financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.
Materials and Supplies
Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials and supplies are capitalized as inventory when purchased and then expensed or capitalized as plant assets when installed, as appropriate. The following table presents a breakdown of materials and supplies at December 31, 2012, and 2011:
(a)
Consists of coal, natural gas, and oil.
Property and Plant
The cost of additions to and betterments of units of property and plant are capitalized. The cost includes labor, material, applicable taxes, and overhead. Interest incurred during construction is capitalized as a cost of assets. Maintenance expenditures are expensed as incurred. When units of depreciable property are retired, the original costs, less salvage values, are charged to accumulated depreciation. Asset removal costs incurred that do not constitute legal obligations are generally expensed as incurred. See Asset Retirement Obligations below and Note 3 - Property and Plant, Net, for additional information.
Depreciation
Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis to the cost basis of such property. Our provision for depreciation in 2012, 2011, and 2010 ranged from 2% to 3% of the average depreciable cost.
Intangible Assets
We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.
At December 31, 2012, and 2011, intangible assets consisted of emission allowances. The book value of emission allowances was less than $1 million at the end of both years. Emission allowances are charged to fuel expense as they are used in operations. Amortization expense based on usage of emission allowances, net of gains from sales, excluding intangible asset impairment charges discussed below, were less than $1 million, $2 million, and $18 million during the years ended December 31, 2012, 2011, and 2010, respectively.
See Note 11 - Impairment and Other Charges for additional information, including a discussion of the 2011 and 2010 intangible asset impairment charges.
Impairment of Long-lived Assets
We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the amount of the carrying value that exceeds the estimated fair value of the assets. In the period in which we determine an asset meets held for sale criteria, we record an impairment charge to the extent the carrying value exceeds its fair value less cost to sell. See Note 11 - Impairment and Other Charges for additional information about impairments of long-lived assets during 2012, 2011, and 2010 and Note 12 - Subsequent Events for an impairment expected to be recorded in 2013.
Environmental Costs
Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. If environmental expenditures are related to facilities currently in use, such as pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset.
Unamortized Debt Discount, Premium, and Expense
Discount, premium, and expense associated with long-term debt are amortized over the lives of the related issues.
Operating Revenue
Operating revenue for electric service is recorded based on net generation in accordance with our PSA with Marketing Company.
Income Taxes
We are included in the consolidated federal income tax return filed by Ameren. As a subsidiary of Ameren, we could be considered jointly and severably liable for assessments of additional tax on the consolidated group. We use an asset and liability approach for our financial accounting and reporting of income taxes, in accordance with authoritative accounting guidance. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are based on statutory tax rates.
Investment tax credits used on tax returns for prior years have been deferred for book purposes; the credits are being amortized over the useful lives of the related investment. Deferred income taxes were recorded on the temporary difference represented by the deferred investment tax credits. See Note 7 - Income Taxes.
We are party to a tax allocation agreement with Ameren that provides for the allocation of consolidated tax liabilities. The tax allocation agreement specifies that each party be allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other parties to the agreement. That allocation is treated as a contribution of capital to the party receiving the benefit.
Noncontrolling Interest
Noncontrolling interest comprised the 20% of EEI we do not own. This noncontrolling interest is classified as a component of equity separate from our equity in the consolidated balance sheet.
The other comprehensive income (loss) attributable to the noncontrolling interest comprised the activity in pension and other postretirement benefit plans. The other comprehensive income (loss) attributed to the noncontrolling interest, net of income taxes, recorded during the years ended December 31, 2012, 2011, and 2010 was $8 million, $(5) million, and $(1) million, respectively. The income tax expense (benefit) recorded during the years ended December 31, 2012, 2011, and 2010 was $6 million, $(4) million and less than $(1) million, respectively.
Accounting Changes and Other Matters
The following is a summary of recently adopted authoritative accounting guidance as well as guidance issued but not yet adopted that could impact us.
Disclosures about Fair Value Measurements
In May 2011, FASB issued additional authoritative guidance
regarding fair value measurements. The guidance amended the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards. The amendments did not affect our results of operations, financial position, or liquidity, as this guidance only requires additional disclosures. We adopted this guidance for the first quarter of 2012. See Note 9 - Fair Value Measurements for the required additional disclosures.
Presentation of Comprehensive Income
In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for us beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect results of operations, financial position, or liquidity.
In February 2013, the FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component. In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes. The amendments will not affect our results of operations, financial position, or liquidity, as this guidance only requires additional disclosures and substantially all the information that this amended guidance requires is already disclosed elsewhere in the financial statements. This guidance will be effective for us beginning in the first quarter of 2013 on a prospective basis.
Disclosures about Offsetting Assets and Liabilities
In December 2011, FASB issued additional authoritative guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The amendments will not affect our results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. This guidance will be effective for us beginning in the first quarter of 2013 with retrospective application required.
Asset Retirement Obligations
Authoritative accounting guidance requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the
liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to make adjustments to AROs based on changes in the estimated fair values of the obligations. Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset. Uncertainties as to the probability, timing, or amount of cash flows associated with AROs affect our estimates of fair value. We have recorded AROs for retirement costs associated with asbestos removal, river structures, and CCR storage facilities.
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2012 and 2011:
(a)
Less than $1 million.
(b)
The fair value estimates related to retirement costs for asbestos removal, river structures and CCR storage facilities were changed. The estimates for asbestos removal and rivers structures changed due to updates in the timing of the projected cash settlements. The estimates for CCR storage facilities changed at certain energy centers due to changing the closure method, updating the cost factor assumptions or updating the timing of the projected cash settlements.
(c)
Includes $5 million in “Other current liabilities” on the balance sheet as of December 31, 2011.
(d)
Fair value estimates were revised for asbestos removal. The estimates for asbestos removal costs at the Hutsonville and Meredosia energy centers decreased because less asbestos than anticipated was found in the energy centers' structures during reviews made after the closure of these energy centers, and because removal was more cost efficient than anticipated due to the closure. Additionally, fair value estimates were revised for updated retirement dates for certain CCR storage facilities.
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Under the terms of that agreement, Ameren agreed to indemnify IPH for certain existing AROs. See Note 12 - Subsequent Events for additional information.
Employee Separation and Other Charges
In each of the past three years, employee separation programs were initiated to reduce positions under the terms and benefits consistent with Ameren’s standard management separation program. We recorded pretax charges related to these programs of $1 million, $4 million, and $4 million in 2012, 2011, and 2010, respectively. The 2012 and 2010 charges were recorded in “Other operations and maintenance” expense on the consolidated statement of income (loss). The 2011 charge related to the closure of the Meredosia and Hutsonville energy centers and was recorded in “Impairment and other charges” on the
consolidated statement of income (loss). See Note 11 - Impairment and Other Charges for additional information.
Asset Sales
In 2012, we completed the sale of land to an affiliate and the sale of an office building to a non-affiliate. As a result of the building sale, we received cash proceeds of $1 million and recognized a $1 million pretax loss from this sale. See Note 2 - Related Party Transactions for information about the land sale.
In June 2010, we completed the sale of 25% of our Columbia CT energy center to the city of Columbia, Missouri. We received cash proceeds of $18 million and recognized a $5 million pretax gain from the sale. In June 2011, we completed the sale of our remaining interest in the Columbia CT energy center to the city of Columbia, Missouri. We received cash proceeds of $45 million and recognized an $8 million pretax gain from the sale. In 2011, we sold additional property and assets for cash proceeds of $4 million, which resulted in pretax gains of $4 million.
NOTE 2 - RELATED PARTY TRANSACTIONS
We have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Below are the material related party agreements.
Put Option Agreement
On March 28, 2012, we entered into a put option agreement with AERG which gave us the option to sell to AERG all, but not less than all, of the Grand Tower, the Gibson City, and the Elgin gas-fired energy centers. Prior to its amendment in March 2013, the purchase price for all three energy centers, if exercised, would be the greater of $100 million or the fair market value of the energy centers, as determined by three third-party appraisers in accordance with the terms of the agreement. Upon exercise of the put option, the $100 million minimum purchase price would be payable to us within one business day. We may exercise the put option at any time through March 28, 2014. If we exercise the put option, the closing of the sale of all three energy centers will be subject to the receipt of all necessary regulatory approvals. In exchange for entering into the put option agreement, we paid AERG a put option premium of $2.5 million. As of December 31, 2012, we had not exercised the put option, nor did we believe it was more likely than not that we would in 2013.
On March 14, 2013, this put option agreement was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley. On March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. Additionally, on March 14,
2013, Ameren entered into a transaction agreement to divest New AER to IPH. Both March 2013 transactions are regarded as subsequent events to the accompanying December 31, 2012 consolidated financial statements. See Note 12 - Subsequent Events for additional information regarding these transactions and the amended put option.
Power Supply Agreements
The following table presents the amount of physical gigawatthour sales and purchases under our related party electric PSAs with Marketing Company, including EEI’s PSA with Marketing Company, for the years ended December 31, 2012, 2011, and 2010:
Genco (parent) has a PSA with Marketing Company, whereby it agreed to sell and Marketing Company agreed to purchase all of the capacity and energy available from its generation fleet. Marketing Company entered into a similar PSA with AERG. Under the PSAs, revenues allocated between Genco and AERG are based on reimbursable expenses and generation. Each PSA will continue through December 31, 2022, and from year to year thereafter unless either party to the respective PSA elects to terminate the PSA by providing the other party with no less than six months advance written notice.
EEI has a PSA with Marketing Company, whereby EEI agreed to sell and Marketing Company agreed to purchase all of the capacity and energy available from EEI’s generation fleet. The price that Marketing Company pays for capacity is set annually based upon prevailing market prices. Marketing Company pays spot market prices for the associated energy. In addition, EEI will at times purchase energy from Marketing Company to fulfill obligations to a nonaffiliated party. This PSA will continue through May 31, 2016, unless either party elects to terminate the PSA by providing the other party with no less than four years advance written notice or five days’ written notice in the event of a default, unless the default is cured within 30 business days.
Support Services Agreements
Ameren Services provides support services to its affiliates, including us. The costs of support services, including wages, employee benefits, professional services, and other expenses, are based on, or are an allocation of, actual costs incurred. In addition, we provide affiliates, primarily Ameren Services, with access to our facilities for administrative purposes. The cost of the rent and facility services are based on, or are an allocation of, actual costs incurred.
AFS provided support services to its affiliates, including us, through December 31, 2010. Effective January 1, 2011, the services previously performed by AFS are performed within Ameren Missouri, Ameren Illinois and AER.
Gas Sales and Transportation Agreement
Under a gas transportation agreement, we acquire gas transportation service from Ameren Missouri. This agreement expires in February 2016.
Intercompany Transfers
In 2012, we transferred various assets from our Hutsonville and Meredosia energy centers to AERG. Both of the energy
centers were retired in 2011. We received cash proceeds in the amount of $3 million. The transfer of the assets was accounted for as a transaction between entities under common control; therefore, we did not recognize a gain on the transfer.
Intercompany Sales
In 2012, we completed the sale of land for cash proceeds of $2 million to ATXI. We recognized a $2 million gain from the sale.
Money Pools
See Note 4 - Short-term Debt and Liquidity for discussion of affiliate borrowing arrangements.
The following table presents the impact of related party transactions for the years ended December 31, 2012, 2011, and 2010. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4 - Short-Term Debt and Liquidity.
(a)
Natural gas sold at fair value.
(b)
Amount less than $1 million.
NOTE 3 - PROPERTY AND PLANT, NET
The following table presents property and plant, net, at December 31, 2012, and 2011:
See Note 11 - Impairment and Other Charges for information regarding a noncash long-lived asset impairment charge recognized in 2012.
The accrued capital expenditures at December 31, 2012, 2011, and 2010 were $3 million, $13 million, and $8 million, which represent noncash investing activity excluded from the statements of cash flows.
NOTE 4 - SHORT-TERM DEBT AND LIQUIDITY
On November 14, 2012, the 2010 Genco Credit Agreement was terminated and not renewed. Should a financing need arise, sources of liquidity include available cash on hand, a return of money pool advances, and money pool borrowings at the discretion of Ameren. On March 14, 2013 we amended and exercised our option to sell our three natural gas-fired energy centers to an affiliate for a purchase price of at least $133 million. With the additional liquidity received through exercising the amended put option agreement, our financing sources are estimated to be adequate to support our operations in 2013. See Note 2 - Related Party Transactions and Note 12 - Subsequent Events for additional information regarding the put option agreement.
The following table summarizes the borrowing activity and relevant interest rates under the 2010 Genco Credit Agreement, prior to its termination, for the years ended December 31, 2012, and 2011:
Money Pool
Ameren established a money pool to coordinate and to provide short-term cash and working capital to its subsidiaries. We have the ability, subject to Ameren parent company authorization, to access funding from the Ameren and Ameren Missouri's $1.0 billion multiyear senior unsecured credit agreement, Ameren and Ameren Illinois' $1.1 billion multiyear senior unsecured credit agreement and Ameren's commercial paper programs through a money pool agreement. We may borrow from or lend to the money pool. When receiving a loan under the money pool agreement, we must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the money pool. The average interest rate for borrowing under the money pool for the year ended December 31, 2012, was 0.61% (2011 - 0.77%).
See Note 2 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements for the years ended December 31, 2012, 2011, and 2010.
NOTE 5 - LONG-TERM DEBT
The following table presents long-term debt outstanding as of December 31, 2012, and 2011:
Indenture Provisions and Other Covenants
We are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not
excessive, and (3) there is no self-dealing on the part of corporate officials.
Our indenture includes provisions that require us to maintain certain interest coverage and debt-to-capital ratios in order for us to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these ratios for the 12 months ended and as of December 31, 2012:
(a)
As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.
(b)
Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Other
borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.
Our debt incurrence-related ratio restrictions under the indenture may be disregarded if both Moody’s and S&P reaffirm the ratings in place at the time of the debt incurrence after considering the additional indebtedness.
As shown in the table above, under the provisions of our indenture, we may not borrow additional funds from external, third-party sources if our interest coverage ratio is less than a specified minimum or if our leverage ratio is greater than a specified maximum. During the first quarter of 2013, our interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and we expect the ratio to remain less than this minimum level through at least 2015. As a result, our ability to borrow additional funds from external, third-party sources is restricted. Our indenture does not restrict intercompany borrowings from Ameren’s non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren’s control. If an intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool would be dependent on consideration by Ameren of the facts and circumstances existing at that time. We will seek to fund operations internally and therefore seek not to rely on financing from Ameren.
In order for us to issue securities in the future, we will have to comply with all applicable requirements in effect at the time of any such issuances.
Our indenture includes restrictions that prohibit payments of dividends on our common stock. Specifically, dividends cannot be paid unless the actual interest coverage ratio for the most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. Based on projections as of December 31, 2012, of operating results and cash flows in 2013 and 2014, we did not believe that we would achieve the minimum interest coverage ratio necessary to pay dividends on our common stock for each of the subsequent four six-month periods ending June 30, 2013, December 31, 2013, June 30, 2014, or December 31, 2014. As a result, we were restricted from paying dividends as of December 31, 2012, and we expect to be unable to pay dividends in 2013, 2014, and 2015. No dividends were paid to our parent, AER, in 2012, 2011, or 2010.
Off-Balance-Sheet Arrangements
At December 31, 2012, we had no off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. We do not expect to engage in any significant off-balance-sheet financing arrangements in the near future.
NOTE 6 - RETIREMENT BENEFITS
We offer defined benefit pension and postretirement benefit plans covering substantially all of our employees. Our employees and retirees, excluding EEI employees and retirees, participate in Ameren’s single-employer pension and other postretirement plans. Ameren’s qualified pension plan is the Ameren Retirement Plan. Ameren also has an unfunded non-qualified pension plan, the Ameren Supplemental Retirement Plan, which is available for certain management employees and retirees to provide a supplemental benefit when their qualified pension plan benefits are reduced to comply with Internal Revenue Code limitations. Ameren’s other postretirement plans are the Ameren Retiree Medical Plan and the Ameren Group Life Insurance Plan. Separately, our EEI employees and retirees participate in EEI’s single-employer pension and other postretirement plans. EEI’s pension plan is the Revised Retirement Plan for Employees of Electric Energy, Inc. EEI’s other postretirement plans are the Group Insurance Plan for Management Employees of Electric Energy, Inc. and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. We consolidate EEI, and therefore, EEI’s plans are reflected in our pension and postretirement balances and disclosures. Ameren and EEI both use a measurement date of December 31 for their pension and postretirement benefit plans.
For our disclosures below, unless otherwise noted, we have reflected the obligations, plan assets, and costs associated with EEI’s pension and postretirement plans as well as an allocation of our share of obligations, plan assets, and costs associated with our participation in Ameren’s single-employer pension and postretirement plans. The allocation of obligations, plan assets, and costs from our participation in Ameren’s single-employer pension plan was based on our employees’ share of Ameren’s total pensionable salaries for all Ameren employees. The allocation of obligations, plan assets, and costs from our participation in Ameren’s single-employer postretirement plans was based on the number of our employees compared to the total number of Ameren employees.
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Under the terms of that agreement, Ameren will retain the portion of Genco’s pension and postretirement benefit obligations associated with current and former employees that are included in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan. Genco will retain the pension and other post-retirement benefit obligations associated with EEI’s current and former employees that are included in the Revised Retirement Plan for Employees of Electric Energy, Inc., the Group Insurance Plan for Management Employees of Electric Energy, Inc., and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. These obligations are estimated at $40 million at December 31, 2012. Genco will also retain the $14 million asset relating to the overfunded status of one of EEI’s postretirement plans. See Note 12 - Subsequent Events for additional information.
We recognize the under-funded status of pension and postretirement plans as a liability on our balance sheet, with offsetting entries to accumulated OCI, in accordance with authoritative accounting guidance. The following table presents the funded status of our pension and postretirement benefit plans as of December 31, 2012, and 2011. It also provides the amounts included in accumulated OCI at December 31, 2012, and 2011, that have not been recognized in net periodic benefit costs. These amounts include the funded status of EEI’s pension and postretirement plans as well as an allocation of our obligation and plan assets included within the Ameren pension and postretirement plans.
(a)
Includes amounts from our participation in Ameren’s single-employer plans and the cost of EEI’s plans.
(b)
Not applicable.
(c)
On December 31, 2012, 74 employees from Ameren Services were transferred to Genco through an internal reorganization.
(d)
In 2012, EEI's pension plan was amended to adjust the calculation of the future benefit obligation for all of its active management employees and certain union-represented employees from a traditional, final pay formula to a cash balance formula. Additionally, in 2012, EEI's management and union-represented postretirement medical benefit plans were amended to adjust for moving to a Medicare Advantage plan.
(e)
In 2011, Ameren’s pension plan was amended to adjust the calculation of the future benefit obligation of approximately 430 union-represented employees from a traditional, final pay formula to a cash balance formula.
(f)
EEI implemented an employee reduction program in 2012, which resulted in a curtailment of its pension and management postretirement benefit plans.
(g)
The Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. was over-funded as of December 31, 2012, which was included in our balance sheet in "Other assets."
The unfunded status of the EEI pension plan at December 31, 2012, and 2011 was $34 million and $39 million respectively. EEI’s postretirement benefits were overfunded by $8 million as of December 31, 2012, and were underfunded by $52 million as of December 31, 2011. As shown in the table above, EEI’s management and labor union postretirement medical benefit plans were amended during 2012 to adjust for moving to a Medicare Advantage plan.
The following table presents the assumptions used to determine our benefit obligations at December 31, 2012, and 2011:
(a)
A weighted average rate of Ameren’s and EEI’s pension and postretirement plans.
Ameren and EEI determine their discount rate assumptions by identifying a theoretical settlement portfolio of high-quality corporate bonds sufficient to provide for their plan's projected benefit payments, pursuant to authoritative accounting guidance on the determination of discount rates used for defined benefit plan obligations. The Ameren settlement portfolio of bonds is selected from a pool of over 600 high-quality corporate bonds. The EEI settlement portfolio of bonds is selected from a pool of over 190 high-quality corporate bonds. For each plan, a single discount rate is then determined that results in a discounted value of that plan's benefit payments that equates to the market value of the selected bonds.
Funding
Pension benefits are based on the employees’ years of service and compensation. The Ameren and EEI pension plans are funded in compliance with income tax regulations and federal funding or regulatory requirements. As a result, we expect to fund the pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. In 2013, we expect to make contributions of $4 million and $6 million to Ameren's pension plan and EEI's pension plan, respectively. In the aggregate, we expect to make contributions of $43 million over the next five years, with $24 million being targeted to the EEI pension plan. These amounts are estimates. The estimates may change based on actual investment performance, changes in interest rates, changes in our assumptions, any pertinent changes in government regulations, any voluntary contributions, or based on Ameren's divestiture of New AER.
The following table presents the cash contributions made to our defined benefit retirement plans during 2012, 2011, and 2010:
Our current funding policies and EEI’s current funding policies are to forego further contributions to their postretirement benefit plans, except as necessary to fund benefit payments. Employer contributions to our postretirement plans were less than $1 million for each year ended December 31, 2012, 2011, and 2010.
Investment Strategy and Policies
Since we receive an allocation, not a specific assignment, of Ameren’s single-employer plan assets, the asset related disclosures below focus on EEI’s plan assets, which are all specifically assigned to us and will be retained by us after Ameren completes its divestiture of New AER, of which we are a part. In accordance with the transaction agreement to divest New AER to IPH, at closing Ameren will retain all of the plan assets within its single-employer pension and postretirement plans.
EEI manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. EEI’s goal is to earn the highest possible return consistent with its tolerance for risk, which is monitored by EEI’s management and board of directors. EEI delegates investment management to specialists in each asset class. As appropriate, EEI provides its investment managers with guidelines that specify allowable and prohibited investment types and regularly monitor manager performance and compliance with investment guidelines.
The expected return on plan assets assumption is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Projected rates of return for each asset class were estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, EEI adjusted the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results
compared with benchmark returns and for the effect of expenses paid from plan assets. EEI will utilize an expected return on plan assets for its pension plan assets and postretirement plan assets of 8% in 2013. No plan assets are expected to be returned to EEI during 2013.
EEI strives to assemble a portfolio of diversified assets that does not create a significant concentration of risks. EEI’s management develops asset allocation guidelines between asset classes, and it creates diversification through investments in assets that differ by type (equity or debt). The diversification of assets is displayed in the target allocation table below. EEI’s management also routinely rebalances the plan assets to adhere to the diversification goals. The following table presents EEI’s target allocations for 2013 and EEI’s pension and postretirement plans’ asset categories as of December 31, 2012, and 2011.
Fair Value Measurements of Plan Assets
Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, 2012. The fair value of an asset is the amount that would be received upon sale in an orderly transaction between market participants at the measurement date. Cash and cash equivalents have initial maturities of three months or less and are recorded at cost plus accrued interest. The carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments. Investments traded in active markets on national or international securities exchanges are valued at closing prices on the last business day on or before the measurement date. Securities traded in over-the-counter markets are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency.
As described above, a portion of Ameren’s pension plan assets is allocated to us. The amount of Ameren pension plan assets allocated to us for financial reporting purposes as of December 31, 2012, was $117 million based on pensionable salaries. The following table sets forth, by level within the fair value hierarchy discussed in Note 9 - Fair Value Measurements, the EEI pension plan assets measured at fair value as of December 31, 2012:
As described above, a portion of Ameren’s pension plan assets is allocated to us. The amount of Ameren pension plan assets allocated to us for financial reporting purposes as of December 31, 2011, was $105 million based on pensionable salaries. The following table sets forth, by level within the fair value hierarchy discussed in Note 9 - Fair Value Measurements, the EEI pension plan assets measured at fair value as of December 31, 2011:
As described above, a portion of Ameren’s postretirement plan assets is allocated to us. The amount of Ameren postretirement plan assets allocated to us for financial reporting purposes as of December 31, 2012, was $21 million based on the number of our non-EEI employees. The following table sets forth, by level within the fair value hierarchy discussed in Note 9 - Fair Value Measurements, the EEI postretirement benefit plans assets measured at fair value as of December 31, 2012:
As described above, a portion of Ameren’s postretirement plan assets is allocated to us. The amount of Ameren postretirement plan assets allocated to us for financial reporting purposes as of December 31, 2011, was $21 million based on the number of our non-EEI employees. The following table sets forth, by level within the fair value hierarchy discussed in Note 9 - Fair Value Measurements, the EEI postretirement benefit plans assets measured at fair value as of December 31, 2011:
Net Periodic Benefit Cost
The following table presents the components of our net periodic benefit cost of the EEI pension and postretirement benefit plans and an allocation of net periodic benefit costs from our participation in Ameren’s pension and postretirement benefit plans during 2012, 2011, and 2010:
(a)
Includes amounts for our participation in Ameren’s single-employer plans and the cost of EEI’s plans.
(b)
Represents EEI's pension and management postretirement benefit plans' curtailment loss recognized as a result of its 2012 employee reduction program.
In addition to the above net periodic benefit cost for pension benefits, we were allocated $2 million, $1 million and $2 million in net periodic benefit costs from Ameren Services employees doing work on our behalf during the years ended December 31, 2012, 2011, and 2010, respectively. We were also allocated less than $1 million, $1 million, and $1 million in net periodic benefit costs for postretirement benefits from Ameren Services employees doing work on our behalf during the years ended December 31, 2012, 2011, and 2010, respectively.
The current year expected return on plan assets is determined primarily by adjusting the prior-year market-related asset value for current year contributions, disbursements, and expected return, plus 25% of the actual return in excess of (or less than) expected return for the four prior years.
The estimated amounts that will be amortized from accumulated OCI into net periodic benefit cost in 2013 are as follows:
(a)
Includes amounts for our participation in Ameren’s single-employer plans and the cost of EEI’s plans.
Prior service cost is amortized on a straight-line basis over the average future service of active participants benefiting under the plan amendment. The net actuarial loss subject to amortization is amortized on a straight-line basis over 10 years.
The expected pension and postretirement benefit payments from qualified trust and company funds and the federal subsidy for postretirement benefits related to prescription drug benefits, which reflect expected future service, as of December 31, 2012, are as follows:
(a)
Includes amounts for our participation in Ameren’s single-employer plans and the cost of EEI’s plans.
The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 2012, 2011, and 2010:
(a)
A weighted average rate of Ameren’s and EEI’s pension and postretirement plans.
The table below reflects the sensitivity to potential changes in key assumptions:
(a)
Includes amounts for our participation in Ameren’s single-employer plans and the cost of EEI’s plans.
Other
Ameren sponsors a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible employees, including our employees, at December 31, 2012. The plan allowed employees to contribute a portion of their compensation in accordance with specific guidelines. Ameren matched a percentage of the employee contributions up to certain limits. Our portion of the matching contribution to the Ameren 401(k) plan was $1 million, $2 million and $1 million for the years ended December 31, 2012, 2011, and 2010, respectively.
NOTE 7 - INCOME TAXES
The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate for the years ended December 31, 2012, 2011, and 2010:
(a)
Relates to change in taxation of prescription drug benefits to retiree participants from the enactment in 2010 of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Bill of 2010.
(b)
Permanent items are treated differently for book and tax purposes and primarily include nondeductible expenses.
The following table presents the components of income tax expense (benefit) for the years ended December 31, 2012, 2011, and 2010:
The Illinois corporate income tax rate increased from 7.3% to 9.5%, starting in January 2011. The tax rate is scheduled to
decrease to 7.75% in 2015, and it is scheduled to return to 7.3% in 2025. This corporate income tax rate increase in Illinois increased current income tax expense in 2011 by $3 million.
The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences at December 31, 2012, and 2011:
(a)
Includes deferred tax assets related to net operating loss and tax credit carryforwards detailed in the table below.
(b)
Includes $11 million in “Other current assets” on the balance sheet as of December 31, 2012.
The following table presents the components of deferred tax assets relating to net operating loss carryforwards and tax credit carryforwards at December 31, 2012:
(a)
These will begin to expire in 2028.
(b)
These will begin to expire in 2019.
(c)
These will begin to expire in 2029.
(d)
These will begin to expire in 2013.
(e)
This balance increased by $1 million during 2012.
Uncertain Tax Positions
A reconciliation of the change in the unrecognized tax benefit balance during the years ended December 31, 2012, 2011, and 2010, is as follows:
Interest charges (income) and penalties accrued on tax liabilities on a pretax basis are recognized as interest charges (income) or miscellaneous expense, respectively, in the statements of income (loss).
A reconciliation of the change in the liability for interest on unrecognized tax benefits during the years ended December 31, 2012, 2011, and 2010, is as follows:
As of December 31, 2012, 2011, and 2010, we had accrued no amount for penalties with respect to unrecognized tax benefits.
We are included in Ameren’s federal income tax return. In 2011, a final settlement for the years 2005 and 2006 was reached with the Internal Revenue Service. It resulted in a reduction in uncertain tax liabilities of $4 million. Ameren’s federal income tax returns for the years 2007 through 2010 are before the Appeals Office of the Internal Revenue Service. Ameren’s federal income tax return for the year 2011 is currently under examination.
It is reasonably possible that a settlement will be reached with the Appeals Office of the Internal Revenue Service in the next twelve months for the years 2007 through 2010. This settlement, primarily related to uncertain tax positions for capitalization versus currently deductible repair expense and research tax deductions, is expected to result in a decrease in uncertain tax benefits of approximately $6 million. In addition, it is reasonably possible that other events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits to increase or decrease. However, we do not believe any such increases or decreases would be material to our results of operations, financial position, or liquidity.
State income tax returns are generally subject to examination for a period of three years after filing of the return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after
formal notification to the states. We do not currently have material state income tax issues under examination, administrative appeals, or litigation.
NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, and power. Such price fluctuations may cause the following:
•
an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;
•
market values of coal and natural gas inventories that differ from the cost of those commodities in inventory; and
•
actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.
The following table presents open gross commodity contract volumes by commodity type as of December 31, 2012, and 2011:
(a)
Accrual contracts include commodity contracts that do not qualify as derivatives. Contracts through December 2017 for coal as of December 31, 2012.
(b)
Contracts through December 2015, October 2016, and April 2015 for coal, fuel oils, and natural gas, respectively, as of December 31, 2012.
(c)
Not applicable.
(d)
Fuel oils consist of heating and crude oil.
(e)
See Note 2 - Related Party Transactions for the amount of physical gigawatthour sales under Genco’s related party electric PSA with Marketing Company, including EEI’s PSA with Marketing Company, as of December 31, 2012.
Authoritative accounting guidance regarding derivative instruments requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 9 - Fair Value Measurements for discussion of our methods of assessing the fair value of derivative instruments. Some of our physical contracts qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.
If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting. Contracts that qualify for cash flow hedge accounting are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of income (loss) and comprehensive income (loss) in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income (loss) and comprehensive income (loss).
Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for, or we do not choose to elect, the NPNS exception or hedge accounting. Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of income (loss) and comprehensive income (loss) in the period in which the change occurs.
Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under
the same master netting arrangement. We did not elect to adopt this guidance for any eligible commodity contracts.
The following table presents the carrying value and balance sheet location of all derivative instruments as of December 31, 2012, and 2011:
The cumulative amount of pretax net losses on interest rate derivative instruments in accumulated OCI was $7 million and $8 million, respectively, as of December 31, 2012 and 2011. These interest rate swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with our April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. Over the next 12 months, $1.4 million of the loss will be amortized. At December 31, 2011, the net loss was offset by net gains associated with interest rate swaps that were a partial hedge of the interest rate on debt issued in June 2002. The swaps covered the first 10 years of debt that has a 30-year maturity, and the gain in OCI was amortized over a 10-year period that began in June 2002. The balance of the gain was fully amortized as of June 30, 2012. The carrying value at December 31, 2011 was less than $1 million.
Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master trading and netting agreements, and reporting daily exposure to senior management.
We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and
Derivatives Association Agreement, a standardized financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) the North American Energy Standards Board Inc. agreement, a
standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.
Concentrations of Credit Risk
In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into one of five groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of December 31, 2012, and 2011, if counterparty groups were to fail completely to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including accrual and NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.
The potential loss on counterparty exposures is reduced by the application of master trading and netting agreements and collateral held to the extent of reducing the exposure to zero. Collateral includes both cash collateral and other collateral held. As of December 31, 2012, we held no collateral to reduce exposure. As of December 31, 2011, we held other collateral which consisted of letters of credit in the amount of $1 million to reduce exposure. The following table presents the potential loss after consideration of the application of master trading and netting agreements and collateral held as of December 31, 2012, and 2011:
Derivative Instruments with Credit Risk-Related Contingent Features
Our commodity contracts contain collateral provisions tied to our credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of December 31, 2012, and 2011, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements assuming (1) the credit risk-related contingent features underlying these agreements were triggered on December 31, 2012, or 2011, respectively, and (2) those counterparties with rights to do so requested collateral:
(a)
Prior to consideration of master trading and netting agreements and including accrual and NPNS contract exposures.
(b)
As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such agreements.
Cash Flow Hedges
The following table presents the pretax net gain or loss for the years ended December 31, 2012, and 2011, associated with derivative instruments designated as cash flow hedges:
(a)
Effective portion of gain (loss).
(b)
Effective portion of (gain) loss on settlements.
(c)
Ineffective portion of gain (loss) and amount excluded from effectiveness testing.
(d)
Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10 year period.
(e)
Less than $1 million.
Other Derivatives
The following table represents the net change in market value associated with derivatives not designated as hedging instruments for the years ended December 31, 2012, and 2011:
NOTE 9 - FAIR VALUE MEASUREMENTS
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:
Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives.
Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain over-the-counter derivative
instruments, including natural gas swaps. Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint.
Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, an evaluation of all sources is performed to identify any anomalies or potential errors.
We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are
classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.
The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the period ended December 31, 2012:
(a)
The derivative asset and liability balances are presented net of counterparty credit considerations.
(b)
Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
(c)
Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
(d)
Counterparty credit risk is only applied to counterparties with derivative asset balances. Genco credit risk is only applied to counterparties with derivative liability balances.
In accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. We recorded net gains of less than $1 million, net losses of less than $1 million, and net gains of less than $1 million in 2012, 2011, and 2010, respectively, related to valuation adjustments for counterparty default risk. The counterparty default risk (asset)/liability valuation adjustment related to derivative contracts totaled less than $1 million and less than $(1) million, respectively, at December 31, 2012 and 2011.
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012, and 2011:
(a)
The derivative asset and liability balances are presented net of counterparty credit considerations.
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of December 31, 2012, and 2011:
(a)
Net gains and losses on fuel oils derivative commodity contracts are recorded in “Operating Expenses - Fuel”, while net gains and losses on power derivative commodity contracts are recorded in “Operating Revenues.”
Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Fuel oils transfers between Level 1 and Level 3 were primarily caused by changes in availability of financial trades observable on electronic exchanges from the previous reporting period for the years ended December 31, 2012 and 2011. Any reclassifications are reported as transfers into or out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur. For the years ended December 31, 2012, and 2011, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts. For the year ended December 31, 2012, there were fuel oil transfers into Level 3 from Level 1 of $1 million and transfers out of Level 3 into Level 1 of $(1) million. For the year ended December 31, 2011, there were fuel oil transfers out of Level 3 and into Level 1 of $(9) million.
See Note 6 - Retirement Benefits for information regarding our participation in Ameren’s and EEI’s pension and postretirement benefit plans.
Our carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy. The estimated fair value of long-term debt is based on the quoted market prices for same or similar issuances for companies with similar credit profiles, which fair value measurement is considered Level 2 in the fair value hierarchy.
The following table presents the carrying amounts and estimated fair values of our long-term debt at December 31, 2012, and 2011:
NOTE 10 - COMMITMENTS AND CONTINGENCIES
We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in these notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.
See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Related Party Transactions and Note 12 - Subsequent Events in this report.
Leases
We lease various facilities, office equipment, plant equipment, and rail cars under operating leases. The following table presents our operating lease obligations at December 31, 2012:
Total rental expense, included in operating expenses, for the years ended December 31, 2012, 2011 and 2010 was $14 million, $12 million, and $13 million, respectively.
Other Obligations
To supply a portion of the fuel requirements of our energy centers, we have entered into various long-term commitments for the procurement of coal and natural gas. The table below presents our estimated fuel and other commitments at December 31, 2012. Included in the “Other” column are minimum purchase commitments under contracts for equipment, design and construction at December 31, 2012.
Environmental Matters
We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. From the beginning phases of siting and development to the ongoing
operation of existing or new electric generation and transmission facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.
In addition to existing laws and regulations, including the Illinois MPS, the EPA is developing environmental regulations that will have a significant impact on the electric generating industry. These regulations could be particularly burdensome for certain companies, including Genco, that operate coal-fired energy centers. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised national ambient air quality standards for fine particulate, SO2, and NO2 emissions; the CSAPR, which would have required further reductions of SO2 emissions and NOx emissions from energy centers; a regulation governing management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from energy centers; revised NSPS for particulate matter, SO2, and NOx emissions from new sources; and new regulations under the Clean Water Act that could require significant capital expenditures such as new water intake structures or cooling towers at our energy centers. The EPA has proposed CO2 limits for new coal-fired and natural gas-fired combined cycle units and is expected to propose limits for existing units in the future. These new and proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation as well as the timing of any such implementation is uncertain, as evidenced by the CSAPR being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia in August 2012. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and/or increased operating costs over the next five to ten years. Compliance with these environmental laws and regulations could be prohibitively expensive. If they are, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.
The estimates in the table below contain all of the known capital costs to comply with existing environmental regulations, including the CAIR, and our assessment of the potential impacts of the EPA's proposed regulation for CCR and the finalized MATS as of December 31, 2012. In addition, the estimates assume that CCR will continue to be regarded as nonhazardous. The estimates do not include the impacts of regulations proposed by
the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures as our evaluation of those impacts is ongoing. The estimates could change significantly depending upon a variety of factors including:
•
additional or modified federal or state requirements;
•
further regulation of greenhouse gas emissions;
•
revisions to CAIR or reinstatement of CSAPR;
•
new national ambient air quality standards or changes to existing standards for ozone, fine particulates, SO2, and NOx emissions;
•
additional rules governing air pollutant transport;
•
regulations under the Clean Water Act regarding cooling water intake structures or effluent standards;
•
finalized regulations classifying CCR as being hazardous or imposing additional requirements on the management of CCR;
•
new technology;
•
expected power prices;
•
variations in costs of material or labor; and
•
alternative compliance strategies or investment decisions.
The decision to make pollution control equipment investments depends on whether the expected future market price for power reflects the increased cost for environmental compliance. During early 2012, the observable market price for power for delivery in that year and in future years sharply declined below 2011 levels primarily because of declining natural gas prices, as well as the impact from the stay of the CSAPR. As a result of this sharp decline in the market price for power, as well as uncertain environmental regulations, we decelerated the construction of two scrubbers at the Newton energy center. The table above includes estimated costs of approximately $20 million annually, excluding capitalized interest, from 2013 through 2017 for the construction of the two Newton energy center scrubbers. Based on the MPS variance granted by the Illinois Pollution Control Board in September 2012, we are currently scheduled to complete the Newton scrubbers by the end of 2019. See additional information below regarding the MPS variance granted by the Illinois Pollution Control Board.
The following sections describe the more significant environmental rules that affect or could affect our operations.
Clean Air Act
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the CAIR). The CAIR required generating facilities in 28 states, including Illinois, and the District of Columbia, to participate in cap-and-trade programs to reduce
annual SO2 emissions, annual NOx emissions, and ozone season NOx emissions.
In December 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the CAIR to the EPA for further action to remedy the rule's flaws, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR replacement. The CSAPR was to become effective on January 1, 2012, for SO2 and annual NOx reductions and on May 1, 2012, for ozone season NOx reductions, with further reductions in 2014. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit issued a stay of the CSAPR. In August 2012, the United States Court of Appeals for the District of Columbia Circuit issued a ruling that vacated the CSAPR in its entirety, finding that the EPA exceeded its authority in imposing the CSAPR's emission limits on states. In January 2013, the full Court of Appeals for the District of Columbia Circuit denied the EPA's request for rehearing. The EPA will continue to administer the CAIR until a new rule is ultimately adopted or the decision to vacate the CSAPR is overturned by the United States Supreme Court.
In December 2011, the EPA issued the MATS under the Clean Air Act, which require emission reductions for mercury and other hazardous air pollutants, such as acid gases, toxic metals, and particulate matter by setting emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. Also, the standards require reductions in hydrogen chloride emissions, which were not regulated previously, and for the first time require continuous monitoring systems for hydrogen chloride, mercury and particulate matter that are not currently in place. The MATS do not require a specific control technology to achieve the emission reductions. The MATS will apply to each unit at a coal-fired power plant; however, emission compliance can be achieved by averaging emissions from similar electric generating units at the same power plant. Compliance is required by April 2015 or, with a case-by-case extension, by April 2016.
Separately, in December 2012, the EPA issued a final rule that made the national ambient air quality standard for fine particulate matter more stringent. States must develop control measures designed to reduce the emission of fine particulate matter below required levels to achieve compliance with the new standard. Such measures may or may not apply to energy centers but could require reductions in SO2 and NOx emissions. Compliance with the finalized rule is required by 2020, or 2025 if an extension of time to achieve compliance is granted. We are currently evaluating the new standard while the state of Illinois develops its attainment plans.
In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standard for ozone. The EPA is required to revisit this standard for ozone again in 2013. The state of Illinois will be required to develop an attainment plan to comply with the 2008 ambient air quality standards for ozone, which could result in additional emission
control requirements for power plants by 2020. We continue to assess the impacts of these new standards.
In September 2012, the Illinois Pollution Control Board granted AER a variance to extend compliance dates for SO2 emission levels contained in the MPS through December 31, 2019, subject to certain conditions described below. The Illinois Pollution Control Board approved AER's proposed plan to restrict its SO2 emissions through 2014 to levels lower than those previously required by the MPS to offset any environmental impact from the variance. The Illinois Pollution Control Board's order also included the following provisions:
•
A schedule of milestones for completion of various aspects of the installation and completion of the scrubber projects at our Newton energy center; the first milestone relates to the completion of engineering design by July 2015 while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019.
•
A requirement for AER to refrain from operating the Meredosia and Hutsonville energy centers through December 31, 2020; however, this restriction does not impact our ability to make the Meredosia energy center available for any parties that may be interested in repowering one of our units to create an oxy-fuel combustion coal-fired energy center designed for permanent carbon dioxide capture and storage.
Under the MPS, AER is required to reduce mercury and NOx emissions by 2015 and SO2 emissions by the end of 2019. The Illinois Pollution Control Board's September 2012 variance gives AER additional time for economic recovery and related power price improvements necessary to support scrubber installations and other pollution controls at some of AER's energy centers. To comply with the MPS and other air emissions laws and regulations, we are installing equipment designed to reduce emissions of mercury, NOx, and SO2. We have installed two scrubbers at the Coffeen energy center. Two additional scrubbers are being constructed at the Newton energy center. We will continue to review and adjust our compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, emission standards required under environmental laws and regulations and compliance technologies, among other factors.
Environmental compliance costs could be prohibitive at some of our energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.
Emission Allowances
The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NOx budget trading program, and the CAIR. Environmental regulations, including those relating to the timing of the installation of pollution control equipment, fuel mix, and the level of operations will have a significant impact on the number of
allowances required for ongoing operations. The CAIR uses the acid rain program's allowances for SO2 emissions and created annual and ozone season NOx allowances. We expect to have adequate CAIR allowances for 2013 to avoid needing to make external purchases to comply with these programs.
Global Climate Change
State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions and to address global climate change. Potential impacts from any climate change legislation or regulation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. As a result of our fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2.
In December 2009, the EPA issued its “endangerment finding” under the Clean Air Act, which stated that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act effective the beginning of 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application.
Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA issued the “Tailoring Rule,” which established new higher emission thresholds beginning in January 2011, for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to its permits upon renewal. Currently, Genco energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology, if any, to control greenhouse gas emissions. New major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. The extent to which the Tailoring Rule could have a material impact on our energy centers depends upon how the state of Illinois applies the EPA's guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants and whether physical changes or changes in operations subject to the rule occur at our energy centers. In June 2012, the United States Court of Appeals for the District of Columbia Circuit upheld the Tailoring Rule.
Separately, in March 2012, the EPA issued the proposed Carbon Pollution Standard for New Power Plants. This proposed NSPS for greenhouse gas emissions would apply only to new fossil-fuel fired electric energy centers and therefore does not affect any of our existing energy centers. We anticipate this proposed rule, if enacted, could make the construction of new coal-fired energy centers in the United States prohibitively expensive. A final rule is expected in 2013. Any federal climate change legislation that is enacted may preempt the EPA's regulation of greenhouse gas emissions, including the Tailoring Rule and the Carbon Pollution Standard for New Power Plants.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force us as well as other similarly situated electric power generators to close some coal-fired facilities earlier than planned, which could lead to possible impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on our results of operations, financial position, and liquidity.
Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address damages resulting from global climate change. In March 2012, the United States District Court for the Southern District of Mississippi dismissed the Comer v. Murphy Oil lawsuit, which alleged that CO2 emissions from several industrial companies, including our energy centers, created atmospheric conditions that intensified Hurricane Katrina, thereby causing property damage. The case has been appealed to the appellate court.
The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, their impact on our coal-fired energy centers and our customers' costs is unknown, but they could result in significant increases in our capital expenditures and operating costs. The compliance costs could be prohibitive at some of our energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.
NSR and Clean Air Litigation
The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the plants implemented modifications. The EPA's inquiries focus on whether projects performed at power plants should have triggered various permitting requirements and the installation of pollution control equipment.
Commencing in 2005, we received a series of information requests from the EPA pursuant to Section 114(a) of the Clean Air Act. The requests sought detailed operating and maintenance history data with respect to our Coffeen, Hutsonville, Meredosia, Newton, and Joppa energy centers. In August 2012, we received a Notice of Violation from the EPA alleging violations of permitting requirements including Title V of the Clean Air Act. The EPA contends that projects performed in 1997, 2006, and 2007 at our Newton energy center violated federal law. We believe our defenses to the allegations described in the Notice of Violation are meritorious. We have included $3 million in “Other current liabilities” on our consolidated balance sheet as of December 31, 2012, relating to this loss contingency. We are unable to predict the outcome of this matter and whether EPA will address this Notice of Violation administratively or through litigation.
Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. We are unable to predict the ultimate resolution of these matters or the costs that might be incurred.
Clean Water Act
In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw more than 2 million gallons of water per day from a body of water and use at least 25 percent of that water exclusively for cooling. Under the proposed rule, affected facilities would be required either to meet mortality limits for aquatic life impinged on the plant's intake screens or to reduce intake velocity to a specified level. The proposed rule also requires existing power plants to meet site-specific entrainment standards or to reduce the cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in June 2013, with compliance expected within eight years thereafter. All coal-fired and combined cycle energy centers with cooling water systems are subject to this proposed rule. The proposed rule did not mandate cooling towers at existing facilities, as other technology options potentially could meet the site-specific standards. We are currently evaluating the proposed rule, and our assessment of the proposed rule's impacts is ongoing. Therefore, we cannot predict at this time the capital or operating costs associated with compliance. The proposed rule, if adopted, could have an adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our energy centers.
In September 2009, the EPA announced its plan to revise the effluent guidelines applicable to steam electric generating units under the Clean Water Act. Effluent guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The EPA is engaged in information collection and analysis activities in support of this rulemaking. It has indicated that it expects to issue a proposed rule in April 2013 and to finalize the rule in May 2014.
We are unable at this time to predict the impact of this development.
Remediation
Ameren Illinois is involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site. Ameren Illinois has been identified by the federal or state governments as a potentially responsible party (PRP) at several contaminated sites. Several of these sites involve facilities that were transferred by CIPS to us in May 2000. As part of the transfer, CIPS, now Ameren Illinois, contractually agreed to indemnify us for remediation costs associated with pre-existing environmental contamination at the transferred sites. As such, we recorded no liability with respect to the obligation related to these claims as of December 31, 2012. The plant transfer agreement between us and CIPS, now Ameren Illinois, will be amended as part of the transaction agreement for Ameren to divest New AER to IPH.
Ash Management
There has been activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. Additionally, in January 2010, the EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements. We are currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. We are also evaluating the potential costs associated with compliance with the proposed
regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted.
Asbestos-related Litigation
Former CIPS energy centers are now owned by us. As a part of the transfer of ownership of the CIPS energy centers, CIPS, now Ameren Illinois, contractually agreed to indemnify us for liabilities associated with asbestos-related claims and environmental conditions arising or existing from activities prior to the transfer in May 2000. The plant transfer agreement between us and CIPS, now Ameren Illinois, will be amended as part of the transaction agreement for Ameren to divest New AER to IPH.
As of December 31, 2012, 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.
Illinois Sales and Use Tax Exemptions and Credits
In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court refused to hear an appeal of the case, and the decision became final. During the second quarter of 2010, we began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to our generation operations. The primary basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. In November 2011, EEI received a notice of proposed tax liability, documenting the state of Illinois' position that EEI did not qualify for the manufacturing exemption it used during 2010. EEI is challenging the state of Illinois' position. In December 2011, EEI filed a request for review by the Informal Conference Board of the Illinois Department of Revenue. We do not believe that it is probable that the state of Illinois will prevail and therefore have not recorded a charge to earnings for the loss contingency. From the second quarter of 2010 through December 31, 2011, we claimed manufacturing exemptions and credits of $19 million, which represents the maximum potential tax liability, excluding any penalties assessed or interest accrued.
We did not claim any additional manufacturing exemptions or credits in 2012 and do not anticipate claiming any additional manufacturing exemptions or credits in 2013, pending discussions with the Illinois Department of Revenue. We are reserving the right to apply for applicable refunds at a later date.
NOTE 11 - IMPAIRMENT AND OTHER CHARGES
The following table summarizes the pretax charges recognized for the years ended December 31, 2012, 2011, and 2010:
Each of the above charges was recorded in the statement of income (loss) and comprehensive income (loss) as “Impairment and other charges.” The impairment charges did not result in a violation of our debt covenants or counterparty agreements. Each of the charges is discussed below.
Long-lived Assets
We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether an impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we would recognize an impairment charge equal to the amount of the carrying value of the assets that exceeds its estimated fair value.
We have experienced decreasing earnings and cash flows from operating activities over the past few years, including in 2012, as margins have declined principally as a result of weaker power prices. In addition, environmental regulations have resulted in significant investment requirements over the same time frame. During the first quarter of 2012, the observable market price for power for delivery in that year and in future years in the Midwest sharply declined below 2011 levels primarily because of declining natural gas prices and the impact of the stay of the CSAPR. As a result of this sharp decline in the market price of power and the related impact on electric margins, we decelerated the construction of two scrubbers at our Newton energy center in February 2012. The sharp decline in the market price of power in the first quarter of 2012 and the related impact on electric margins, as well as the deceleration of construction of the Newton energy center scrubber project, caused us to evaluate, during the first quarter of 2012, whether the carrying values of our coal-fired energy centers were recoverable. The first quarter test demonstrated that the estimated undiscounted future cash flows of our long-lived assets exceeded their carrying values, which resulted in no impairment during the first quarter of 2012.
Ameren, which owns our parent company, is increasingly focused on allocating its capital resources to those opportunities that it believes offer the most attractive risk-adjusted return potential, and is specifically focused on growing earnings from its rate-regulated operations through investment under constructive regulatory frameworks. Ameren has sought to have us fund our operations internally and not rely on financing from Ameren. In December 2012, Ameren determined that it intended to, and it was probable that it would, exit its merchant generation business, of which we are a part, before the end of the previously estimated useful lives of that business's long-lived assets. In consideration of this determination, Ameren began planning to reduce, and ultimately eliminate, our reliance on Ameren's financial support and shared services support.
Ameren's December 2012 decision that it intended to, and it was probable that it would, reduce and ultimately eliminate its financial support and shared services support provided to us, caused us to evaluate, during the fourth quarter of 2012, whether the carrying values of our energy centers were recoverable. Based on the expectation of reduced financial support from Ameren, together with existing power market conditions and cash flow requirements, we estimated we would more likely than not need liquidity from an asset sale to support our operations before the put option agreement was due to expire on March 28, 2014. As a result of the expectation at that time that it was more likely than not that we would sell the Elgin energy center for liquidity purposes, the Elgin energy center's carrying value exceeded its estimated undiscounted future cash flows. Accordingly, we recorded a noncash pretax impairment charge of $70 million to reduce the carrying value of the Elgin energy center to its estimated fair value. The estimated undiscounted future cash flows for our other energy centers exceeded their carrying values and therefore were unimpaired. Under the applicable accounting guidance, if undiscounted future cash flows from these long-lived assets exceed their carrying values, the assets are deemed unimpaired, and no impairment loss is recognized, even if the carrying values of the assets exceed estimated fair values.
We will continue to monitor the market price for power and the related impact on electric margin, our liquidity needs, and other events or changes in circumstances that indicate that the carrying value of our energy centers may not be recoverable as compared to their undiscounted cash flows. We could recognize additional, material long-lived asset impairment charges in the future if estimated undiscounted future cash flows no longer exceed carrying values for long-lived assets. This may occur either as a result of factors outside our control, such as changes in market prices of power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of our energy centers, and also as a result of factors that may be within our control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell its energy centers. As of December 31, 2012, the carrying value of our long-lived assets was $2.2 billion.
In December 2011, we ceased operations of our Meredosia and Hutsonville energy centers. As a result, we recorded a noncash pretax asset impairment charge of $26 million to reduce
the carrying value of the Meredosia and Hutsonville energy centers to their estimated fair values, a $4 million impairment of materials and supplies, and $4 million for severance costs. See Note 1 - Summary of Significant Accounting Policies for further information regarding severance costs.
During the third quarter of 2010, the aggregate impact of a sustained decline in market prices for electricity, industry market multiples became observable at lower levels than previously estimated, and potentially more stringent environmental regulations being enacted caused us to evaluate if the carrying value of our energy centers were recoverable. The Meredosia energy center's carrying value exceeded its estimated undiscounted future cash flows. As a result, during 2010, we recorded a noncash pretax asset impairment charge of $64 million to reduce the carrying value of the Meredosia energy center to its estimated fair value.
Key assumptions used in the determination of estimated undiscounted cash flows of our long-lived assets tested for impairment included forward price projections for energy and fuel costs, the expected life or duration of ownership of the long-lived assets, environmental compliance costs and strategies, and operating costs. Those same cash flow assumptions, along with a discount rate and a terminal year earnings multiple, were used to estimate the fair value of the Elgin energy center during the fourth quarter of 2012 and the Meredosia energy center during the third quarter of 2010. These assumptions are subject to a high degree of judgment and complexity. The fair value estimate of these long-lived assets was based on a combination of the income approach, which considers discounted cash flows, and the market approach, which considers market multiples for similar assets within the electric generation industry. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements. We assess impairment at the energy center level.
Goodwill
Our goodwill was associated with the acquisition of an additional 20% interest in EEI in 2004. We have one reporting unit, Merchant Generation. We evaluated goodwill for impairment as of October 31 of each year, or more frequently if events and circumstances indicated that the asset might be impaired. Goodwill impairment testing is a two-step process. The first step involves a comparison of the estimated fair value of a reporting unit with its carrying amount. If the estimated fair value of the reporting unit exceeds the carrying value, goodwill of the reporting unit is considered unimpaired. If the carrying amount of the reporting unit exceeds its estimated fair value, a second step is performed to measure the amount of impairment, if any. The second step of the goodwill impairment test compares the implied fair value of the reporting unit's goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined by allocating the estimated fair value of the reporting unit to the estimated fair value of its existing assets and liabilities. The unallocated portion of the estimated fair value of the reporting unit is the implied fair value of goodwill. If the implied fair value of
goodwill is less than the carrying amount, an impairment loss equivalent to the difference is recorded as a reduction of goodwill and a charge to operating expense.
During the third quarter of 2010, we concluded that events had occurred and circumstances had changed which, when considered in the aggregate, indicated that it was more likely than not that the fair value of our reporting unit was less than its carrying value. Such events and circumstances included the sustained decline in market prices for electricity, industry market multiples became observable at lower levels than previously estimated, and potentially more stringent environmental regulations being enacted. In July 2010, the EPA issued the proposed CSAPR. The proposed CSAPR, along with other pending regulations, was expected to result in a significant increase in capital and operations and maintenance expenditures for our energy centers.
Our reporting unit failed step one of the 2010 interim impairment test, as the reporting unit's carrying value exceeded its estimated fair value. Therefore, in order to measure the goodwill impairment in step two, we estimated the implied fair value of our goodwill. We determined that the implied fair value of goodwill was less than the carrying amount of goodwill, indicating that our goodwill was impaired. Based on the results of step two of the impairment test, we recorded a noncash impairment charge of $65 million, which represented all of the goodwill assigned to our reporting unit.
The fair value estimate of our reporting unit was based on a combination of the income approach, which considers discounted future cash flows, and the market approach, which considers market comparables within the electric generation industry. Key assumptions in the determination of fair value included the use of an appropriate discount rate, estimated five-year cash flows, and observable industry market multiples. We used our best estimates in making these evaluations. We considered various factors, including forward price projections for energy and fuel costs, environmental compliance costs, and operating costs. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements.
Intangible Assets
Prior to 2010, we expected to use our SO2 emission allowances for ongoing operations. In July 2010, the EPA issued the proposed CSAPR, which would have restricted the use of existing SO2 emission allowances. As a result, we no longer expected that all of our SO2 emission allowances would be used in operations. Therefore, during 2010, we recorded a $41 million pretax impairment charge to reduce the carrying value of our SO2 emission allowances to their estimated fair value.
In July 2011, the EPA issued CSAPR, which created new allowances for SO2 and NOx emissions, and restricted the use of preexisting SO2 and NOx allowances to the acid rain program and to the NOx budget trading program, respectively. As a result, observable market prices for existing emission allowances declined materially. Consequently, we recorded a $1 million
noncash pretax impairment charge relating to its emission allowances.
The fair value of the SO2 and NOx emission allowances was based on observable and unobservable inputs, which were classified as Level 3 inputs for fair value measurements.
NOTE 12 - SUBSEQUENT EVENTS
Transaction Agreement
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Under the terms of the transaction agreement, AER will effect a reorganization that will, among other things, transfer all of the assets and liabilities of AER, other than (i) any outstanding debt obligations of AER to Ameren or its other subsidiaries, except for a note from AER to Ameren relating to cash collateral that will remain outstanding at closing of the sale of New AER, (ii) all of the issued and outstanding equity interests in Medina Valley, which have been distributed to Ameren, and (iii) the assets and the environmental and closure liabilities associated with Genco’s closed Meredosia and Hutsonville energy centers, to a newly created limited liability company that is a direct wholly owned subsidiary of AER, New AER. IPH will acquire all of the equity interests in New AER.
Ameren will retain the portion of Genco’s pension and postretirement benefit obligations associated with current and former employees that are included in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan. These obligations are estimated at $45 million at December 31, 2012, after consideration of a potential curtailment gain of Ameren’s postretirement plans as a result of the transaction. Genco will retain the pension and other postretirement benefit obligations associated with EEI’s current and former employees that are included in the Revised Retirement Plan for Employees of Electric Energy, Inc., the Group Insurance Plan for Management Employees of Electric Energy, Inc., and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. These obligations are estimated at $40 million at December 31, 2012. Genco will also retain the $14 million asset relating to the overfunded status of one of EEI’s postretirement plans.
Ameren will retain Genco’s Meredosia and Hutsonville energy centers, which are no longer in operation and had no plant asset value as of December 31, 2012. Ameren will also retain AROs associated with these energy centers, estimated at $27 million as of December 31, 2012. Upon the closing, with the exception of certain agreements, such as supply obligations to Ameren Illinois, a note from AER to Ameren relating to cash collateral that will remain outstanding at closing, and Genco money pool advances, all intercompany agreements and debt between New AER and its subsidiaries, on the one hand, and Ameren and its affiliates, on the other hand, will be terminated, without any costs or other liability or obligation to IPH or New AER and its subsidiaries. Obligations terminated will include Genco’s tax payable to Ameren Illinois, which was $45 million as of December 31, 2012, and will be assumed by Ameren.
Ameren’s retention of Genco’s liabilities for pension and postretirement benefit obligations relating to Ameren’s plans, the Meredosia and Hutsonville energy centers and those two energy centers’ related AROs, the tax payable to Ameren Illinois, and related deferred tax balances associated with each transferred balance will be accounted for as transactions between entities under common control. As such, we expect the balances to be transferred at book value with an offset to additional paid in capital.
In addition, if this transaction is completed, we expect the tax basis of our property, plant and equipment to decrease and our deferred tax assets related to federal income tax net operating loss carryforwards to decrease with corresponding offsets to equity. The amount of any such decrease is dependent on the value and timing of the transaction.
Genco's $825 million in aggregate principal amount of senior notes will remain outstanding following the closing and will continue to be solely obligations of Genco. Additionally, per the transaction agreement, Ameren will cause $70 million of cash to be retained at Genco.
As described in more detail below under “Amended Put Option Agreement, Asset Purchase Agreement and Guaranty”, as a condition to the transaction agreement, Genco will receive cash proceeds from the exercise of its option under the March 28, 2012 put option agreement, as amended, for the sale to Medina Valley of the Elgin, Gibson City and Grand Tower gas-fired energy centers in an amount equal to the greater of $133 million or the appraised value of such energy centers. If these gas-fired energy centers are subsequently sold by Medina Valley within two years of the put option closing, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the amounts previously paid to Genco. Ameren plans to commence a sale process for these three gas-fired energy centers as soon as reasonably practical.
IPH has agreed to honor collective bargaining agreements for Genco’s union employees. In addition, IPH has agreed to provide each Genco management employee who continues to work for IPH, for at least one year following the closing, a base rate of pay not less than that in effect with respect to the employee immediately before the closing and incentive compensation and employee benefits that, in the aggregate, are no less favorable than the incentive compensation and employee benefits provided to similarly situated employees of IPH and its affiliates from time to time.
Completion of the New AER sale to IPH is subject to the receipt of approvals from FERC and approval of certain license transfers by the FCC. Additionally, as a condition to IPH’s obligation to complete the transaction, the Illinois Pollution Control Board must approve the transfer to IPH of AER’s variance related to the Illinois MPS. Ameren’s and IPH’s obligation to complete the transaction is also subject to other customary closing conditions, including the material accuracy of each company’s representations and warranties and the compliance, in all material respects, with each company’s
covenants. The transaction agreement contains customary representations and warranties of Ameren and IPH, including representations and warranties of Ameren with respect to the business being sold. The transaction agreement also contains customary covenants of Ameren and IPH, including the covenant of Ameren that New AER, including Genco, will be operated in the ordinary course prior to the closing.
Ameren expects the closing will occur in the fourth quarter of 2013. If the closing does not occur on or before March 14, 2014, subject to a one-month extension to obtain FERC approval, either party may elect to terminate the transaction agreement if the inability to close the transaction by such date is not the result of the failure of the terminating company to fulfill any of its obligations under the transaction agreement.
Amended Put Option Agreement, Asset Purchase Agreement and Guaranty
See Note 2 - Related Party Transactions for additional information regarding the original put option agreement between Genco and AERG that was signed on March 28, 2012.
Prior to the entry into the transaction agreement as discussed above, (i) the original put option agreement between Genco and AERG was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley and (ii) Genco exercised its option under the amended put option agreement to sell the Elgin, Gibson City and Grand Tower gas-fired energy centers to Medina Valley. As a result, on March 14, 2013, Medina Valley paid to us an initial payment of $100 million in accordance with the terms of the amended put option agreement. In connection with the amended put option agreement, Ameren's guaranty, dated March 28, 2012, was modified to replace all references to AERG with references to Medina Valley.
Pursuant to the amended put option agreement, Genco and
Medina Valley have entered into an asset purchase agreement, dated as of March 14, 2013. Genco and Medina Valley will engage three appraisers to conduct a fair market valuation of the Elgin, Gibson City and Grand Tower gas-fired energy centers, which valuations will be averaged and subject to adjustment at the closing of the asset purchase agreement to reflect the liabilities associated with the Elgin, Gibson City and Grand Tower gas-fired energy centers transferred to Medina Valley under the terms of the asset purchase agreement. At the asset purchase agreement closing, Medina Valley will pay Genco additional consideration in an amount equal to the greater of (i) $33 million, or (ii) the appraised value of the Elgin, Gibson City and Grand Tower gas-fired energy centers less the initial payment of $100 million, and Genco will sell and transfer to Medina Valley all of its rights in the Elgin, Gibson City and Grand Tower gas-fired energy centers as a condition to the transaction agreement. If these gas-fired energy centers are subsequently sold by Medina Valley within two years of the asset purchase agreement closing, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the amounts previously paid to Genco.
The asset purchase agreement contains customary representations, warranties and covenants of Genco and Medina Valley. The consummation of the transactions contemplated by the asset purchase agreement is subject to certain conditions, including the receipt of FERC approval and other customary conditions.
Based upon the asset purchase agreement, we expect to record an after-tax charge to earnings estimated to be in the range of $125 million to reflect the expected loss on the sale of the Elgin, Gibson City and Grand Tower gas-fired energy centers. Beginning with the quarter ended March 31, 2013, we expect to classify the Elgin, Gibson City and Grand Tower gas-fired energy centers as held for sale in our consolidated financial statements.
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions)
(a)
The sum of quarterly amounts, including per share amounts, may not equal amounts reported for year-to-date periods. This is due to the effects of rounding.
(b)
Includes pretax "Impairment and other charges" of $70 million and $35 million recorded during the years ended December 31, 2012, and 2011, respectively. See Note 11 - Impairment and Other Charges, for additional information.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES.
Genco was required to comply with Section 404 of the Sarbanes-Oxley Act of 2002 and related SEC regulations as to management’s assessment of internal control over financial reporting for the 2012 fiscal year.
(a)
Evaluation of Disclosure Controls and Procedures
As of December 31, 2012, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of Genco’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on those evaluations, as of December 31, 2012, the principal executive officer and principal financial officer concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in Genco’s reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.
(b)
Management’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision of and with the participation of management, including the principal executive officer and principal financial officer, an evaluation was conducted of the effectiveness of internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). After making that evaluation, management concluded that internal control over financial reporting was effective as of December 31, 2012.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness into future periods are subject to the risk that internal controls might become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures might deteriorate.
(c)
Change in Internal Control
There has been no change in internal control over financial reporting during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION.
Genco has no information reportable under this item that was required to be disclosed in a report on SEC Form 8-K during the fourth quarter of 2012 that has not previously been reported on an SEC Form 8-K.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
This item is omitted in reliance on General Instruction (I)(2) of Form 10-K.
To encourage ethical conduct in its financial management and reporting, Ameren has adopted a Code of Ethics that applies to the principal executive officer, the president, the principal financial officer, the principal accounting officer, the controller, and the treasurer of each of the Ameren companies, including Genco. The Ameren companies make available free of charge through Ameren's website (www.ameren.com) the Code of Ethics. Any amendment to the Code of Ethics and any waiver from a provision of the Code of Ethics will be posted on Ameren's website within four business days following the date of the amendment or waiver.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
This item is omitted in reliance on General Instruction (I)(2) of Form 10-K.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
This item is omitted in reliance on General Instruction (I)(2) of Form 10-K.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE.
This item is omitted in reliance on General Instruction (I)(2) of Form 10-K.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES.
Information required by this Item of Form 10-K is identical to the information that is included in Ameren’s definitive proxy statement for the 2013 annual meeting of shareholders filed pursuant to SEC Regulations 14A; it is incorporated herein by reference. Specifically, reference is made to the following section of Ameren’s definitive proxy statement: “Independent Registered Public Accounting Firm.”
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a)(3) Exhibits
Reference is made to the Exhibit Index commencing on page 69.
(b) Exhibits
Exhibits are listed in the Exhibit Index commencing on page 69.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
AMEREN ENERGY GENERATING COMPANY (registrant)
Date:
April 1, 2013
By
/s/ Steven R. Sullivan
Steven R. Sullivan
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ Steven R. Sullivan
Chairman, President and Chief Executive Officer
and Director (Principal Executive Officer)
April 1, 2013
Steven R. Sullivan
/s/ Martin J. Lyons, Jr.
Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer)
April 1, 2013
Martin J. Lyons, Jr.
/s/ Bruce A. Steinke
Senior Vice President, Finance and Chief Accounting Officer (Principal Accounting Officer)
April 1, 2013
Bruce A. Steinke
Director
Daniel F. Cole
*
Director
April 1, 2013
Gregory L. Nelson
*By
/s/ Martin J. Lyons, Jr.
April 1, 2013
Martin J. Lyons, Jr.
Attorney-in-Fact
EXHIBIT INDEX
The documents listed below are being filed or have previously been filed on behalf of the registrant and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith:
The file number reference for Genco's filings with the SEC is 333-56594.
*Compensatory plan or arrangement.
**Attached as Exhibit 101 to this report is the following financial information for Genco's Annual Report on Form 10-K for the year ended December 31, 2012, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statement of Income (Loss) and Comprehensive Income (Loss) for the years ended December 31, 2012, 2011, and 2010, (ii) the Consolidated Balance Sheet at December 31, 2012 and December 31, 2011, (iii) the Consolidated Statement of Cash Flows for the years ended December 31, 2012, 2011, and 2010, (iv) the Consolidated Statement of Stockholder’s Equity for the years ended December 31, 2012, 2011, and 2010, and (v) the Combined Notes to the Financial Statements for the year ended December 31, 2012. These exhibits are deemed furnished and not filed pursuant to Rule 406T of Regulation S-T.
Genco hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above that Genco has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.