Item 1A. RISK FACTORS
Some important factors, in addition to others specifically addressed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” that could have a material negative impact on our operations, financial results and financial condition, or could cause our actual results or outcomes to differ materially from any projected outcome contained in any forward-looking statement in this report, include:
Risks Relating to Substantial Indebtedness and Debt Agreements
Our substantial leverage could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry, expose us to interest rate risk to the extent of our variable rate debt and prevent us from meeting obligations under the various debt agreements governing our indebtedness.
We are highly leveraged. As of December 31, 2009, our consolidated principal amount of debt (short term borrowings and long-term debt, including amounts due currently) totaled $44.191 billion (see Note 12 to Financial Statements). Our substantial leverage could have important consequences, including:
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making it more difficult for us to make payments on our indebtedness;
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requiring a substantial portion of cash flow from operations to be dedicated to the payment of principal and interest on indebtedness, therefore reducing our ability to use our cash flow to fund operations, capital expenditures and future business opportunities and execute our strategy;
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increasing our vulnerability to adverse economic, industry or competitive developments;
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exposing us to the risk of increased interest rates because, as of December 31, 2009, taking into consideration interest swap transactions, 10% of our long-term borrowings were at variable rates of interest;
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limiting our ability to make strategic acquisitions or causing us to make non-strategic divestitures;
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limiting our ability to obtain additional financing for working capital, capital expenditures, product development, debt service requirements, acquisitions and general corporate or other purposes, or to refinance existing debt;
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limiting our ability to adjust to changing market conditions, and
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placing us at a competitive disadvantage compared to competitors who are less highly leveraged and who therefore, may be able to take advantage of opportunities that we cannot due to our substantial leverage.
A substantial amount of this indebtedness is comprised of our indebtedness under the TCEH Senior Secured Facilities, substantially all of which matures in October 2014. We may not be able to refinance the TCEH Senior Secured Facilities or our other existing indebtedness because of our high levels of debt and debt incurrence restrictions under our debt agreements or because of generally adverse conditions in credit markets.
Despite our current high indebtedness level, we may still be able to incur substantially more indebtedness. This could further exacerbate the risks associated with our substantial indebtedness.
We may be able to incur additional indebtedness in the future. Although our debt agreements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and under certain circumstances, the amount of indebtedness, including secured indebtedness, that could be incurred in compliance with these restrictions could be substantial. If new debt is added to our existing debt levels, the related risks that we now face would intensify.
Increases in interest rates may negatively impact our operating results and financial condition.
Certain of our borrowings are at variable rates of interest. To the extent the interest rate for such borrowings is not fixed by interest rate swaps, an increase in interest rates would have a negative impact on our results of operations by causing an increase in interest expense.
At December 31, 2009, we had $4.221 billion aggregate principal amount of variable rate long-term indebtedness (excluding $1.135 billion of long-term borrowings associated with the TCEH Letter of Credit Facility that are invested at a variable rate), taking into account interest rate swaps that fix the interest rate on $16.30 billion in notional amount of variable rate indebtedness. As a result, as of December 31, 2009, a 100 basis point increase in interest rates would increase our annual interest expense by approximately $42 million. See discussion of interest rate swap transactions in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Significant Activities and Events.”
Interest expense and related charges for the year ended December 31, 2009 was $2.912 billion.
EFH Corp.’s and its subsidiaries’ debt agreements contain restrictions that limit flexibility in operating our businesses.
EFH Corp.’s and its subsidiaries’ debt agreements contain various covenants and other restrictions that limit the ability of EFH Corp. and/or its restricted subsidiaries to engage in specified types of transactions and may adversely affect our ability to operate our businesses. These covenants and other restrictions limit EFH Corp.’s and/or its restricted subsidiaries’ ability to, among other things:
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incur additional indebtedness or issue preferred shares;
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pay dividends on, repurchase or make distributions in respect of capital stock or make other restricted payments;
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make investments;
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sell or transfer assets;
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create liens;
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consolidate, merge, sell or otherwise dispose of all or substantially all of its or their assets;
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enter into transactions with its or their affiliates, and
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repay, repurchase or modify certain subordinated and other material debt.
There are a number of important limitations and exceptions to these covenants and other restrictions. See Note 12 to Financial Statements for a description of these covenants and other restrictions.
Under the TCEH Senior Secured Facilities, TCEH is required to maintain a leverage ratio below specified levels. TCEH’s ability to maintain its leverage ratio below such levels can be affected by events beyond its control, and there can be no assurance that it will meet any such ratio.
A breach of any of these covenants or restrictions could result in an event of default under one or more of EFH Corp.’s and its subsidiaries’ debt agreements, including as a result of cross default provisions. Upon the occurrence of an event of default under one of the debt agreements, the lenders could elect to declare all amounts outstanding under that debt agreement to be immediately due and payable and/or terminate all commitments to extend further credit. Such actions by those lenders could cause cross defaults under EFH Corp.’s and its subsidiaries’ other indebtedness. If EFH Corp. or one of its subsidiaries was unable to repay those amounts, the lenders could proceed against any collateral granted to them to secure such indebtedness. If lenders accelerate the repayment of borrowings, EFH Corp. or such subsidiary may not have sufficient assets and funds to repay those borrowings.
In addition, as described in Note 1 to Financial Statements, EFH Corp. and Oncor have implemented a number of “ring-fencing” measures to enhance the credit quality of Oncor, its immediate parent, Oncor Holdings, and Oncor Holdings’ other subsidiaries. Those measures include, among other things:
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Oncor being treated as an unrestricted subsidiary with respect to EFH Corp.’s indebtedness;
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Oncor not being restricted from incurring its own indebtedness;
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Oncor not guaranteeing or pledging any of its assets to secure the indebtedness of any member of the Texas Holdings Group, and
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restrictions on dividends, and the right of the independent members of Oncor’s board of directors and the primary noncontrolling member of Oncor to block the payment of dividends.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our debt agreements, which may not be successful.
Our ability to make scheduled payments on or to refinance debt obligations depends on our financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If cash flows and capital resources are insufficient to fund EFH Corp.’s and its subsidiaries’ debt service obligations, we or our subsidiaries could face substantial liquidity problems and might be forced to reduce or delay investments and capital expenditures, or to dispose of assets or operations, seek additional capital or restructure or refinance indebtedness. These alternative measures may be costly or may not be successful or adequate for us and our subsidiaries to meet our debt service obligations. Additionally, EFH Corp.’s and its subsidiaries’ debt agreements limit the use of the proceeds from many dispositions of assets or operations. As a result, we may not be allowed, under these documents, to use proceeds from these dispositions to satisfy our debt service obligations.
Under the terms of TCEH’s debt agreements, TCEH is restricted from making certain payments to EFH Corp.
EFH Corp. is a holding company and substantially all of its consolidated assets are held by its subsidiaries. As of December 31, 2009, TCEH and its subsidiaries held approximately 70% of EFH Corp.’s consolidated assets and for the year ended December 31, 2009, TCEH and its subsidiaries represented approximately 83% of EFH Corp.’s consolidated revenues. Accordingly, EFH Corp. depends upon TCEH for a significant amount of its cash flows and ability to pay its obligations. However, under the terms of TCEH’s debt agreements, TCEH is restricted from making certain payments, including dividends and loans, to EFH Corp., except in the form of certain loans to cover certain of EFH Corp.’s obligations and dividends and distributions in certain other limited circumstances if permitted by applicable state law. Further, TCEH’s debt agreements do not permit such intercompany loans to service EFH Corp. debt unless required for EFH Corp. to pay principal, premium and interest when due on indebtedness incurred by EFH Corp. to finance the Merger, indebtedness in existence prior to the Merger, or any indebtedness incurred by EFH Corp. to replace, refund or refinance such debt. Such loans are also permitted to service other debt, subject to limitations on the amount of the loans. As a result, unless and until the net proceeds from any new debt issuance by EFH Corp. are used to replace, refund or refinance EFH Corp. debt, intercompany loans from TCEH to EFH Corp. to make payments on such debt will be limited. In addition, TCEH is prohibited from making some loans to EFH Corp. if certain events of default under TCEH’s debt agreements have occurred and are continuing.
Under the terms of the indentures governing the EFIH Notes, Intermediate Holding is restricted from making certain payments to EFH Corp.
EFH Corp. is a holding company and substantially all of its consolidated assets are held by its subsidiaries. As of December 31, 2009, Intermediate Holding and its subsidiaries held approximately 27% of EFH Corp.’s consolidated assets and for the year ended December 31, 2009, Intermediate Holding and its subsidiaries represented approximately 17% of EFH Corp.’s consolidated revenues. Accordingly, EFH Corp. depends upon Intermediate Holding for a significant amount of its cash flows and ability to pay its obligations. However, under the terms of the indenture governing the EFIH Notes, Intermediate Holding is restricted from making certain payments, including dividends and loans, to EFH Corp., except in limited circumstances.
EFH Corp. has a very limited ability to control activities at Oncor due to structural and operational “ring-fencing” measures.
EFH Corp. depends upon Oncor for a significant amount of its cash flows and ability to pay its obligations. However, EFH Corp. has a very limited ability to control the activities of Oncor. As part of the “ring-fencing” measures implemented by EFH Corp. and Oncor, a majority of the members of Oncor’s board of directors are required to meet the New York Stock Exchange requirements for independence in all material respects, and the unanimous consent of such directors is required for Oncor to take certain actions. In addition, any new independent directors are required to be appointed by the nominating committee of Oncor Holdings’ board of directors, a majority of whose members are independent directors. No member of EFH Corp.’s management is a member of Oncor’s board of directors. Under Oncor Holdings’ and Oncor’s organizational documents, EFH Corp. has the right, indirectly, to consent to new issuances of equity securities by Oncor, material transactions with third parties involving Oncor outside of the ordinary course of business, actions that cause Oncor’s assets to increase the level of jurisdiction of the FERC, any changes to the state of formation of Oncor, material changes to accounting methods not required by GAAP, and actions that fail to enforce certain tax sharing obligations between Oncor and EFH Corp. In addition, there are restrictions on Oncor’s ability to make distributions to its members, including indirectly to EFH Corp.
Risks Relating to Structure
EFH Corp. is a holding company and its obligations are structurally subordinated to existing and future liabilities and preferred stock of its subsidiaries.
EFH Corp.’s cash flows and ability to meet its obligations are largely dependent upon the earnings of its subsidiaries and the payment of such earnings to EFH Corp. in the form of dividends, distributions, loans or otherwise, and repayment of loans or advances from EFH Corp. These subsidiaries are separate and distinct legal entities and have no obligation to provide EFH Corp. with funds for its payment obligations. Any decision by a subsidiary to provide EFH Corp. with funds for its payment obligations, whether by dividends, distributions, loans or otherwise, will depend on, among other things, the subsidiary’s results of operations, financial condition, cash requirements, contractual restrictions and other factors. In addition, a subsidiary’s ability to pay dividends may be limited by covenants in its existing and future debt agreements or applicable law.
Because EFH Corp. is a holding company, its obligations to its creditors are structurally subordinated to all existing and future liabilities and existing and future preferred stock of its subsidiaries that do not guarantee such obligations. Therefore, with respect to subsidiaries that do not guarantee EFH Corp.’s obligations, EFH Corp.’s rights and the rights of its creditors to participate in the assets of any subsidiary in the event that such a subsidiary is liquidated or reorganized are subject to the prior claims of such subsidiary’s creditors and holders of such subsidiary’s preferred stock. To the extent that EFH Corp. may be a creditor with recognized claims against any such subsidiary, EFH Corp.’s claims would still be subject to the prior claims of such subsidiary’s creditors to the extent that they are secured or senior to those held by EFH Corp. Subject to restrictions contained in financing arrangements, EFH Corp.’s subsidiaries may incur additional indebtedness and other liabilities.
Oncor may or may not make any distributions to EFH Corp.
Upon the consummation of the Merger, EFH Corp. and Oncor implemented certain structural and operational “ring-fencing” measures based on principles articulated by rating agencies and commitments made by Texas Holdings and Oncor to the PUCT and the FERC to further enhance Oncor’s credit quality. These measures were put into place to mitigate Oncor’s credit exposure to the Texas Holdings Group and to reduce the risk that the assets and liabilities of Oncor would be substantively consolidated with the assets and liabilities of the Texas Holdings Group in the event of a bankruptcy of one or more of those entities.
As part of the ring-fencing measures, a majority of the members of the board of directors of Oncor are required to be, and are, independent from EFH Corp. Any new independent directors of Oncor are required to be appointed by the nominating committee of Oncor Holdings. The organizational documents of Oncor give these independent directors, acting by majority vote, and, during certain periods, any director designated by Texas Transmission, the express right to prevent distributions from Oncor if they determine that it is in the best interests of Oncor to retain such amounts to meet expected future requirements. Accordingly, there can be no assurance that Oncor will make any distributions to EFH Corp.
In addition, Oncor’s organizational documents limit Oncor’s distributions to EFH Corp. through December 31, 2012 to an amount not to exceed Oncor’s net income (determined in accordance with US GAAP, subject to certain defined adjustments, including goodwill impairments) and prohibit Oncor from making any distribution to EFH Corp. so long as and to the extent that such distribution would cause Oncor’s regulatory capital structure to exceed the debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.
In March 2009, the PUCT awarded Oncor the right to construct approximately $1.3 billion of transmission lines and facilities associated with its CREZ Transmission Plan (see discussion in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulation and Rates”). With the award, it is likely Oncor will incur additional debt. In addition, Oncor may incur additional debt in connection with other investments in infrastructure or technology. Accordingly, while Oncor is required to maintain a debt-to-equity ratio of 60% debt to 40% equity, there can be no assurance that Oncor’s equity balance will be sufficient to maintain the required debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, thereby restricting Oncor from making any distributions to EFH Corp.
Risks Relating to Businesses
Our businesses are subject to ongoing complex governmental regulations and legislation that have impacted, and may in the future impact, our businesses and/or results of operations.
Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory initiatives regarding the restructuring of the energy industry, including competition in the generation and sale of electricity. We will need to continually adapt to these changes.
Our businesses are subject to changes in state and federal laws (including PURA, the Federal Power Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act and the Energy Policy Act of 2005), changing governmental policy and regulatory actions (including those of the PUCT, the Electric Reliability Organization, the Texas Regional Entity, the RRC, the TCEQ, the FERC, the EPA and the NRC) and the rules, guidelines and protocols of ERCOT with respect to matters including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, construction and operation of transmission facilities, acquisition, disposal, depreciation and amortization of regulated assets and facilities, recovery of costs and investments, decommissioning costs, return on invested capital for regulated businesses, market behavior rules, present or prospective wholesale and retail competition and environmental matters. TCEH, along with other market participants, is subject to electricity pricing constraints and market behavior and other competition-related rules and regulations under PURA that are administered by the PUCT and ERCOT, and, with respect to any wholesale power sales outside the ERCOT market, is subject to market behavior and other competition-related rules and regulations under the Federal Power Act that are administered by the FERC. Changes in, revisions to, or reinterpretations of existing laws and regulations (for example, with respect to prices at which TCEH may sell electricity, the required permits for the three lignite-fueled generation units recently completed or currently under construction or the cost of emitting greenhouse gases) may have an adverse effect on our businesses.
The Texas Legislature meets every two years, and from time to time bills are introduced and considered that could materially affect our businesses. There can be no assurance that future action of the Texas Legislature will not result in legislation that could have a material adverse effect on us and our financial prospects.
PURA, the PUCT, ERCOT, the RRC and the Office of Public Utility Council (OPC) are subject to a “Sunset” review by the Texas Sunset Advisory Commission. PURA will expire, and the PUCT and the RRC will be abolished, on September 1, 2011 unless extended by the Texas Legislature following such review. If any of PURA, the PUCT, ERCOT, the RRC or the OPC are not renewed by the Texas Legislature pursuant to Sunset review, it could have a material effect on our business.
Sunset review is the regular assessment of the continuing need for a state agency to exist, and is grounded in the premise that an agency will be abolished unless legislation is passed to continue its functions. The Texas Sunset Advisory Commission (Sunset Commission) closely reviews each agency and recommends action on each agency to the Texas Legislature, which action may include modifying or even abolishing the agency. Of the twenty-seven agencies scheduled for Sunset review by the Sunset Commission in 2009 and 2010, four hold primary interest for us: the PUCT, the OPC, the RRC and ERCOT, which are subject to a focused, limited scope, or special purpose review. These agencies, for the most part, govern and operate the electricity and mining markets in Texas upon which our business model is based. PURA, which expires September 1, 2011, is also subject to Sunset review. If the Texas Legislature fails to renew PURA or any of these agencies, it could result in a significant restructuring of the Texas electricity market or regulatory regime that could have a material impact on our business. There can be no assurance that future action of the Sunset Commission will not result in legislation that could have a material adverse effect on us and our financial prospects.
Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputation damage, and have a material adverse effect on our results of operations, and the litigation environment in which we operate poses a significant risk to our businesses.
We are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, environmental and injuries and damages issues, among other matters. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these assessments and estimates, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These assessments and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from current assessments and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on our results of operations. In addition, judges and juries in the State of Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage and business tort cases. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment in the State of Texas poses a significant business risk.
We are involved in the ordinary course of business in permit applications and renewals, and we are exposed to the risk that certain of our operating permits may not be granted or renewed on satisfactory terms. Failure to obtain and maintain the necessary permits to conduct our businesses could have a material adverse effect on our results of operations.
We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative proceedings. See Item 3, “Legal Proceedings - Regulatory Investigations and Reviews.” While we cannot predict the outcome of any regulatory investigation or administrative proceeding, any such regulatory investigation or administrative proceeding could result in us incurring material penalties and/or other costs and have a material adverse effect on our results of operations.
TXU Energy may lose a significant number of retail customers due to competitive marketing activity by other retail electric providers.
TXU Energy faces competition for customers. Competitors may offer lower prices and other incentives, which, despite TXU Energy’s long-standing relationship with customers, may attract customers away from TXU Energy.
In some retail electricity markets, TXU Energy’s principal competitor may be the incumbent REP. The incumbent REP has the advantage of long-standing relationships with its customers, including well-known brand recognition.
In addition to competition from the incumbent REP, TXU Energy may face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services who may develop businesses that will compete with TXU Energy. Some of these competitors or potential competitors may be larger or better capitalized than TXU Energy. If there is inadequate potential margin in these retail electricity markets, it may not be profitable for TXU Energy to compete in these markets.
TCEH’s revenues and results of operations may be negatively impacted by decreases in market prices for power, decreases in natural gas prices, and/or decreases in market heat rates.
TCEH (our largest business) is not guaranteed any rate of return on capital investments in its competitive businesses. We market and trade electricity and natural gas, including electricity from our own generation facilities and generation contracted from third parties, as part of our wholesale markets operation. TCEH’s results of operations depend in large part upon market prices for electricity, natural gas, uranium, coal and transportation in its regional market and other competitive markets and upon prevailing retail electricity rates, which may be impacted by actions of regulatory authorities. Market prices may fluctuate substantially over relatively short periods of time. Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, at times there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules and other mechanisms to address volatility and other issues in these markets.
Some of the fuel for our generation facilities is purchased under short-term contracts. Prices of fuel, including diesel, natural gas, coal, and nuclear fuel, may also be volatile, and the price we can obtain for electricity sales may not change at the same rate as changes in fuel costs. In addition, we purchase and sell natural gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting obligations.
Volatility in market prices for fuel and electricity may result from the following:
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volatility in natural gas prices;
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volatility in market heat rates;
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volatility in coal and rail transportation prices;
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severe or unexpected weather conditions;
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seasonality;
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changes in electricity and fuel usage;
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illiquidity in the wholesale power or other markets;
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transmission or transportation constraints, inoperability or inefficiencies;
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availability of competitively-priced alternative energy sources;
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changes in supply and demand for energy commodities, including nuclear fuel and related enrichment and conversion services;
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changes in generation efficiency;
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outages at our generation facilities or those of our competitors;
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changes in the credit risk or payment practices of market participants;
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changes in production and storage levels of natural gas, lignite, coal, crude oil, diesel and other refined products;
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natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events, and
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federal, state and local energy, environmental and other regulation and legislation.
All of our generation facilities are located in the ERCOT market, a market with limited interconnections to other markets. Wholesale electricity prices in the ERCOT market generally correlate with the price of natural gas because marginal electricity demand is generally supplied by natural gas-fueled generation facilities.
Wholesale electricity prices also correlate with market heat rates (a measure of efficiency of the marginal price-setting generator of electricity), which could fall if demand for electricity were to decrease or if additional generation facilities are built in ERCOT. Accordingly, the contribution to earnings and the value of our baseload (lignite/coal-fueled and nuclear) generation assets, which provided a substantial portion of our supply volumes in 2009, are dependent in significant part upon the price of natural gas and market heat rates. As a result, our baseload generation assets could significantly decrease in profitability and value if natural gas prices or market heat rates fall.
Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedging transactions may not work as planned or hedge counterparties may default on their obligations.
We cannot fully hedge the risk associated with changes in commodity prices, most notably natural gas prices, or market heat rates because of the expected useful life of our generation assets and the size of our position relative to market liquidity. To the extent we have unhedged positions, fluctuating commodity prices and/or market heat rates can materially impact our results of operations and financial position, either favorably or unfavorably.
To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge portions of purchase and sale commitments, fuel requirements and inventories of natural gas, lignite, coal, crude oil, diesel fuel and refined products, and other commodities, within established risk management guidelines. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in over-the-counter markets or on exchanges. Although we devote a considerable amount of time and effort to the establishment of risk management procedures, as well as the ongoing review of the implementation of these procedures, the procedures in place may not always function as planned and cannot eliminate all the risks associated with these activities. For example, we hedge the expected needs of our wholesale and retail customers, but unexpected changes due to weather, natural disasters, market constraints or other factors could cause us to purchase power to meet unexpected demand in periods of high wholesale market prices or resell excess power into the wholesale market in periods of low prices. As a result of these and other factors, we cannot precisely predict the impact that risk management decisions may have on our businesses, results of operations or financial position.
With the tightening of credit markets, there has been some decline in the number of market participants in the wholesale energy commodities markets, resulting in less liquidity, particularly in the ERCOT electricity market. Participation by financial institutions and other intermediaries (including investment banks) has particularly declined. Extended declines in market liquidity could materially affect our ability to hedge our financial exposure to desired levels.
To the extent we engage in hedging and risk management activities, we are exposed to the risk that counterparties that owe us money, energy or other commodities as a result of market transactions will not perform their obligations. Should the counterparties to these arrangements fail to perform, we might be forced to enter into alternative hedging arrangements or honor the underlying commitment at then-current market prices. In such event, we might incur losses in addition to amounts, if any, already paid to the counterparties. ERCOT market participants are also exposed to risks that another ERCOT market participant may default on its obligations to pay ERCOT for power taken, in which case such costs, to the extent not offset by posted security and other protections available to ERCOT, may be allocated to various non-defaulting ERCOT market participants, including us.
Our use of assets as collateral for hedging arrangements could be materially impacted if certain proposed legislation regarding the regulation of over-the-counter financial derivatives were to be enacted and be applicable to us.
The Obama Administration has proposed financial market reforms with respect to the currently unregulated Over-the-Counter (OTC) financial derivatives market. As a result, the US House of Representatives has approved a bill to regulate OTC derivatives. The bill would require certain entities to clear OTC derivatives that are currently traded on the bilateral market through exchanges, which require that all collateral be in the form of cash. We have entered into a significant number of asset-backed OTC derivatives to hedge risks associated with commodity and interest rate exposure. The US House of Representatives legislation would not require us to clear our OTC derivatives through exchanges. However, other proposals would have required such clearing, and it is not evident what, if any, US Senate legislation might be approved. If we were required to clear such transactions, we would likely be precluded from using our noncash assets as collateral for hedging arrangements. This preclusion could have a material impact on our liquidity, particularly if the final legislation does not provide for the grandfathering of existing OTC derivatives. As a result, if applied to our OTC derivatives transactions, legislation that impairs the use of asset-backed transactions could significantly increase our costs of entering into OTC derivatives and/or could significantly limit our ability to enter into OTC derivatives and hedge our commodity and interest rate risks. We cannot predict whether or when final legislation will be enacted or whether the US House of Representatives bill exemptions will be included in any final legislation.
We may suffer material losses, costs and liabilities due to ownership and operation of the Comanche Peak nuclear generation facility.
The ownership and operation of a nuclear generation facility involves certain risks. These risks include:
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unscheduled outages or unexpected costs due to equipment, mechanical, structural or other problems;
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inadequacy or lapses in maintenance protocols;
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the impairment of reactor operation and safety systems due to human error;
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the costs of storage, handling and disposal of nuclear materials, including availability of storage space;
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the costs of procuring nuclear fuel;
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the costs of securing the plant against possible terrorist attacks;
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limitations on the amounts and types of insurance coverage commercially available, and
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uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives.
The prolonged unavailability of Comanche Peak could materially affect our financial condition and results of operations. The following are among the more significant of these risks:
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Operational Risk - Operations at any nuclear generation facility could degrade to the point where the facility would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the facility to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Furthermore, a shut-down or failure at any other nuclear generation facility could cause regulators to require a shut-down or reduced availability at Comanche Peak.
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Regulatory Risk - The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Unless extended, the NRC operating licenses for Comanche Peak Unit 1 and Unit 2 will expire in 2030 and 2033, respectively. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.
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Nuclear Accident Risk - Although the safety record of Comanche Peak and other nuclear generation facilities generally has been very good, accidents and other unforeseen problems have occurred both in the US and elsewhere. The consequences of an accident can be severe and include loss of life, injury, lasting negative health impact, and property damage. Any accident, or perceived accident, could result in significant liabilities and damage our reputation. Any such resulting liability from a nuclear accident could exceed our resources, including insurance coverage.
The operation and maintenance of electricity generation and delivery facilities involves significant risks that could adversely affect our results of operations and financial condition.
The operation and maintenance of electricity generation and delivery facilities involves many risks, including, as applicable, start-up risks, breakdown or failure of facilities, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel source or the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output, efficiency or reliability, the occurrence of any of which could result in lost revenues and/or increased expenses. A significant number of our facilities were constructed many years ago. In particular, older generating equipment and transmission and distribution equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to keep operating at peak efficiency or reliability. The risk of increased maintenance and capital expenditures arises from (a) increased starting and stopping of generation equipment due to the volatility of the competitive generation market, (b) any unexpected failure to generate electricity, including failure caused by breakdown or forced outage and (c) damage to facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events. Further, our ability to successfully and timely complete capital improvements to existing facilities or other capital projects is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject to additional costs and/or the write-off of our investment in the project or improvement.
Insurance, warranties or performance guarantees may not cover all or any of the lost revenues or increased expenses, including the cost of replacement power. Likewise, the ability to obtain insurance, and the cost of and coverage provided by such insurance, could be affected by events outside our control.
Our cost of compliance with environmental laws and regulations and our commitments, and the cost of compliance with new environmental laws, regulations or commitments could materially adversely affect our results of operations and financial condition.
We are subject to extensive environmental regulation by governmental authorities. In operating our facilities, we are required to comply with numerous environmental laws and regulations and to obtain numerous governmental permits. We may incur significant additional costs beyond those currently contemplated to comply with these requirements. If we fail to comply with these requirements, we could be subject to civil or criminal liabilities and fines. Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions, all of which could result in significant additional costs beyond those currently contemplated to comply with existing requirements.
In conjunction with the building of three new generation units, we have committed to reduce emissions of mercury, NOX and SO2 through the installation of emissions control equipment at both the new and existing lignite-fueled generation units. We may incur significantly greater costs than those contemplated in order to achieve this commitment.
We have formed a Sustainable Energy Advisory Board that advises us in our pursuit of technology development opportunities that, among other things, are designed to reduce our impact on the environment. Any adoption of Sustainable Energy Advisory Board recommendations may cause us to incur significant costs in addition to the costs referenced above.
We may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals or if we fail to obtain, maintain or comply with any such approval, the operation and/or construction of our facilities could be stopped, curtailed or modified or become subject to additional costs.
In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities that we have acquired, leased or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Another party could, depending on the circumstances, assert an environmental claim against us or fail to meet its indemnification obligations to us.
Our financial condition and results of operations may be materially adversely affected if new federal and/or state legislation or regulations are adopted to address global climate change.
In recent years, a growing concern has emerged about global climate change and how greenhouse gas (GHG) emissions, such as CO2, contribute to global climate change. Several bills addressing climate change have been introduced in the US Congress or discussed by the Obama Administration that are intended to address climate change using different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), a tax on carbon emissions (carbon-tax), incentives for the development of low-carbon technology and federal renewable portfolio standards. In addition, a number of federal court cases have been recently decided with respect to GHG emissions, including a US Supreme Court case holding that CO2 and other GHG emissions are pollutants subject to regulation under the Clean Air Act. Some commentators believe that the possible outcome from these decisions include future judicial regulation of GHG emissions.
We produce GHG emissions from the combustion of fossil fuels at our generation facilities. For 2008, we estimate that our generation facilities produced 55 million short tons of CO2 based on continuously monitored data reported to and approved by the EPA. The two new lignite-fueled units that achieved substantial completion (as defined in the EPC Agreement for the units) in fall of 2009 and the one new lignite-fueled unit that is expected to achieve substantial completion (as defined in the EPC Agreement for the unit) in mid-2010 will generate additional CO2 emissions. Because a substantial portion of our generation portfolio consists of lignite/coal-fueled generation facilities, our financial condition and results of operations could be materially adversely affected by the enactment of any legislation or regulation that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes upon those that produce GHG emissions. For example, to the extent a cap-and-trade program is adopted, we may be required to incur material costs to reduce our GHG emissions or to procure emission allowances or credits to comply with such a program. To the extent that the EPA begins to regulate GHGs under the Clean Air Act or the judiciary imposes limits on GHG emissions, we could incur material costs to reduce our GHG emissions. If a significant number of our investors, customers or others refuse to do business with us because of our GHG emissions, it could have a material adverse effect on our results of operations, financial position and liquidity.
Our financial condition and results of operations may be materially adversely affected by the effects of extreme weather conditions.
We could be subject to the effects of extreme weather. Extreme weather conditions could stress our transmission and distribution system or our generation facilities resulting in increased maintenance and capital expenditures. Extreme weather events, including hurricanes or storms or other natural disasters, could be destructive and result in casualty losses that are not ultimately offset by insurance proceeds or in increased capital expenditures or costs, including supply chain costs.
Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or damage to other operating equipment, which could result in us foregoing sales of electricity and lost revenue. Similarly, an extreme weather event might affect the availability of generation and transmission capacity, limiting our ability to source or deliver electricity to where it is needed. These conditions, which cannot be reliably predicted, could have an adverse consequence by requiring us to seek additional sources of electricity when wholesale market prices are high or to seek to sell excess electricity when those market prices are low.
The rates of Oncor’s electricity delivery business are subject to regulatory review, and may be reduced below current levels, which could adversely impact Oncor’s financial condition and results of operations.
The rates charged by Oncor are regulated by the PUCT and certain cities and are subject to cost-of-service regulation and annual earnings oversight. This regulatory treatment does not provide any assurance as to achievement of earnings levels. Oncor’s rates are regulated based on an analysis of Oncor’s costs and capital structure, as reviewed and approved in a regulatory proceeding. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCT will judge all of Oncor’s costs to have been prudently incurred, that the PUCT will not reduce the amount of invested capital included in the capital structure that Oncor’s rates are based upon, or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of Oncor’s costs, including regulatory assets reported in the balance sheet, and the return on invested capital allowed by the PUCT.
In addition, in connection with the Merger, Oncor has made several commitments to the PUCT regarding its rates. For example, Oncor committed that it will, in rate cases after its 2008 general rate case through proceedings initiated prior to December 31, 2012, support a cost of debt that will be no greater than the then-current cost of debt of electric utilities with investment grade credit ratings equal to Oncor’s ratings as of October 1, 2007. As a result, Oncor may not be able to recover all of its debt costs if they are above those levels.
Our growth strategy, including investment in three new lignite-fueled generation units and Oncor’s capital program, may not be executed as planned, which could adversely impact our financial condition and results of operations.
There can be no guarantee that the execution of our growth strategy will be successful. As discussed below, our growth strategy is dependent upon many factors. Changes in laws, regulations, markets, costs, the outcome of on-going litigation or other factors could negatively impact the execution of our growth strategy, including causing management to change the strategy. Even if we are able to execute our growth strategy, it may take longer than expected, and costs may be higher than expected.
There can be no guarantee that the execution of the lignite-fueled generation development program will be successful. While we have experience in operating lignite-fueled generation facilities, we have limited recent experience in constructing, commissioning and starting-up such facilities. To the extent construction is not managed efficiently and to a timely conclusion, cost overruns may occur, resulting in the overall program costing significantly more than anticipated. This may also result in delays in the expected online dates for the facilities resulting in less overall income than projected. While we believe we can acquire the resources needed to effectively execute this program, we are exposed to the risk that we may not be able to attract and retain skilled labor, at projected rates, for constructing, commissioning and starting-up these new facilities.
Our lignite-fueled generation development program is subject to changes in laws, regulations and policies that are beyond our control. Changes in law, regulation or policy regarding commodity prices, power prices, electricity competition or solid-fuel generation facilities or other related matters could adversely impact this program. In recent years, global warming has received significant media attention, which has resulted in legislators focusing on environmental laws, regulations and policies. Changes in environmental law, regulation or policy, such as regulations of emissions of carbon dioxide, could adversely impact this program. Although we have received permits to construct and operate the new units that are a part of the lignite-fueled generation development program, some of these permits are subject to ongoing litigation. See Item 3, “Legal Proceedings - Litigation Related to Generation Facilities” for further detail regarding such ongoing litigation. An adverse ruling on these matters could materially and adversely effect the implementation of this program.
Our lignite-fueled generation development program is subject to changes in the electricity market, primarily ERCOT, that are beyond our control. If demand growth is less than expected or if other generation companies build a significant amount of new generation assets in ERCOT, market prices of power could fall such that the new generation capacity becomes uneconomical. In addition, any unanticipated reduction in wholesale electricity prices, market heat rates and natural gas prices, which could occur for a variety of reasons, could adversely impact this program. Even if we enter into hedges to reduce such exposures, we would still be subject to the credit risk of our counterparties.
There can be no guarantee that the execution of Oncor’s capital deployment program for its electricity delivery facilities will be successful, and there can be no assurance that the capital investments Oncor intends to make in connection with its electricity delivery business will produce the desired reductions in cost and improvements to service and reliability. Furthermore, there can be no guarantee that Oncor’s capital investments, including the investment of approximately $1.3 billion (based on ERCOT cost estimates for CREZ construction projects) to construct CREZ-related transmission lines and facilities, will ultimately be recoverable through rates or, if recovered, that they will be recovered on a timely basis. There can also be no assurance that the PUCT’s award of CREZ construction projects will not be delayed, modified or otherwise vacated through judicial or administrative actions. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulation and Rates.”
Ongoing performance improvement initiatives may not achieve desired cost reductions and may instead result in significant additional costs if unsuccessful.
The implementation of performance improvement initiatives identified by management may not produce the desired reduction in costs and if unsuccessful, may instead result in significant additional costs as well as significant disruptions in our operations due to employee displacement and the rapid pace of changes to organizational structure and operating practices and processes. Such additional costs or operational disruptions could have an adverse effect on our businesses and financial prospects.
TXU Energy’s retail business is subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to its reputation and/or the results of operations of the retail business.
TXU Energy’s retail business requires access to sensitive customer data in the ordinary course of business. Examples of sensitive customer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history, credit bureau data, credit and debit card account numbers, drivers license numbers, social security numbers and bank account information. TXU Energy’s retail business may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to the retail business. If a significant breach occurred, the reputation of TXU Energy’s retail business may be adversely affected, customer confidence may be diminished, or TXU Energy’s retail business may be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on the business and/or results of operations.
TXU Energy relies on the infrastructure of local utilities or independent transmission system operators to provide electricity to, and to obtain information about, its customers. Any infrastructure failure could negatively impact customer satisfaction and could have a material negative impact on its business and results of operations.
TXU Energy depends on transmission and distribution facilities owned and operated by unaffiliated utilities, as well as Oncor’s facilities, to deliver the electricity it sells to its customers. If transmission capacity is inadequate, TXU Energy’s ability to sell and deliver electricity may be hindered, it may have to forgo sales or it may have to buy more expensive wholesale electricity than is available in the capacity-constrained area. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where TXU Energy has a significant number of customers. The cost to provide service to these customers may exceed the cost to provide service to other customers, resulting in lower profits. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to TXU Energy’s customers could negatively impact the satisfaction of its customers with its service.
TXU Energy offers bundled services to its retail customers, with some bundled services offered at fixed prices and for fixed terms. If TXU Energy’s costs for these bundled services exceed the prices paid by its customers, its results of operations could be materially adversely affected.
TXU Energy offers its customers a bundle of services that include, at a minimum, electricity plus transmission, distribution and related services. The prices TXU Energy charges for its bundle of services or for the various components of the bundle, any of which may be fixed by contract with the customer for a period of time, could fall below TXU Energy’s underlying cost to provide the components of such services.
TXU Energy’s REP certification is subject to PUCT review.
The PUCT may at any time initiate an investigation into whether TXU Energy is compliant with PUCT Substantive Rules and whether it has met all of the requirements for REP certification, including financial requirements. Any removal or revocation of a REP certification would mean that TXU Energy would no longer be allowed to provide electricity service to retail customers. Such decertification would have an adverse effect on the company and its financial prospects. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulations and Rates” for a discussion of new rules regarding REP certification.
Changes in technology or increased electricity conservation efforts may reduce the value of our generation plants and/or Oncor’s electricity delivery facilities and may significantly impact our businesses in other ways as well.
Research and development activities are ongoing to improve existing and alternative technologies to produce electricity, including gas turbines, fuel cells, microturbines, photovoltaic (solar) cells and concentrated solar thermal devices. It is possible that advances in these or other technologies will reduce the costs of electricity production from these technologies to a level that will enable these technologies to compete effectively with our traditional generation plants. While demand for electricity has been generally increasing throughout the US, the rate of construction and development of new, more efficient generation facilities may exceed increases in demand in some regional electric markets. Consequently, where we have facilities, the profitability and market value of our generation assets could be significantly reduced. Changes in technology could also alter the channels through which retail customers buy electricity. To the extent self-generation facilities become a more cost-effective option for certain customers, our revenues could be materially reduced.
Also, electricity demand could be reduced by increased conservation efforts and advances in technology, which could likewise significantly reduce the value of our generation assets and electricity delivery facilities. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Effective energy conservation by our customers could result in reduced energy demand or significantly slow the growth in demand. Such reduction in demand could materially reduce our revenues. Furthermore, we may incur increased capital expenditures if we are required to invest in conservation measures.
Our revenues and results of operations may be adversely impacted by decreases in market prices of power due to the development of wind generation power sources.
A significant amount of investment in wind generation in the ERCOT market over the past few years has increased overall wind power generation capacity. Generally, the increased capacity has led to lower wholesale electricity prices (driven by lower market heat rates) in the zones at or near wind generation development, especially in, but not exclusive to, the ERCOT West zone where most of the new wind power generation is located. As a result, the profitability of our generation facilities and power purchase contracts, including certain wind generation power purchase contracts, has been impacted and could be further impacted by the effects of the wind power generation, and the value could significantly decrease if wind power generation has a material sustained effect on market heat rates.
Our revenues and results of operations may be adversely impacted as ERCOT transitions the current zonal market structure to a nodal wholesale market.
Substantially all of our competitive businesses are located in the ERCOT market, which is currently in the process of transitioning from a zonal market structure with four congestion management zones to a nodal market structure that will directly manage congestion on a localized basis. In a nodal market, the prices received and paid for power will be based on pricing determined at specific interconnection points on the transmission grid (i.e., Locational Marginal Pricing), which could result in lower revenues or higher costs for our competitive businesses. This market structure change could have a significant impact on the profitability and value of our competitive businesses depending on how the Locational Marginal Pricing develops. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulations and Rates - Wholesale Market Design.”
Our future results of operations may be negatively impacted by settlement adjustments determined by ERCOT related to prior periods.
ERCOT is the independent system operator that is responsible for maintaining reliable operation of the bulk electric power supply system in the ERCOT market. Its responsibilities include the clearing and settlement of electricity volumes and related ancillary services among the various participants in the deregulated Texas market. Settlement information is due from ERCOT within two months after the operating day, and true-up settlements are due from ERCOT within six months after the operating day. Likewise, ERCOT has the ability to resettle any operating day at any time after the six month settlement period, usually the result of a lingering dispute, an alternative dispute resolution process or litigated event. As a result, we are subject to settlement adjustments from ERCOT related to prior periods, which may result in charges or credits impacting our future reported results of operations.
Our results of operations and financial condition could be negatively impacted by any development or event beyond our control that causes economic weakness in the ERCOT market.
We derive substantially all of our revenues from operations in the ERCOT market, which covers approximately 75% of the geographical area in the State of Texas. As a result, regardless of the state of the economy in areas outside the ERCOT market, economic weakness in the ERCOT market could lead to reduced demand for electricity in the ERCOT market. Such a reduction could have a material negative impact on our results of operations and financial condition.
EFH Corp.’s (or any applicable subsidiary’s) credit ratings could negatively affect EFH Corp.’s (or the pertinent subsidiary’s) ability to access capital and could require EFH Corp. or its subsidiaries to post collateral or repay certain indebtedness.
Downgrades in EFH Corp.’s or any of its applicable subsidiaries’ long-term debt ratings generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease and could trigger liquidity demands pursuant to the terms of new commodity contracts, leases or other agreements. In November 2009, the credit rating agencies announced certain rating actions shortly after completion of the EFH Corp. debt exchange transaction discussed in Note 12 to Financial Statements. S&P established B+ ratings for the new EFH Corp. 9.75% Notes and EFIH Notes. Moody’s affirmed its Caa1 corporate family rating and negative outlook for EFH Corp. and TCEH but upgraded its probability of default rating to Caa2 from Ca as it determined that the final transaction results did not represent a “distressed exchange.” In addition, Moody’s established Caa3 ratings for the new EFH Corp. 9.75% Notes and EFIH Notes and completed upgrades of certain securities due to results of the exchange. Fitch established a rating of B+ on the new EFH Corp. 9.75% Notes and EFIH Notes resulting from the exchange and downgraded its ratings of the EFH Corp. 10.875% and Toggle Notes by one notch to B from B+. Additionally, Fitch affirmed its ratings and outlook for EFH Corp., EFC Holdings and TCEH. The ratings and stable outlook for Oncor were unaffected by the exchange and were affirmed by all three agencies. Future transactions by EFH Corp. or any of its subsidiaries, including the issuance of additional debt or the consummation of a transaction similar to the November 2009 debt exchanges, could result in temporary or permanent downgrades of EFH Corp.’s or its subsidiaries’ credit ratings.
Most of EFH Corp.’s large customers, suppliers and counterparties require an expected level of creditworthiness in order for them to enter into transactions. If EFH Corp.’s (or an applicable subsidiary’s) credit ratings decline, the costs to operate its businesses would likely increase because counterparties could require the posting of collateral in the form of cash-related instruments, or counterparties could decline to do business with EFH Corp. (or its applicable subsidiary).
Continued market volatility may have impacts on our businesses and financial condition that we currently cannot predict.
Because our operations are capital intensive, we expect to rely over the long-term upon access to financial markets (particularly the attainment of liquidity facilities) as a significant source of liquidity for capital requirements not satisfied by cash-on-hand, operating cash flows or our revolving credit facilities. Recently, the capital and credit markets have been experiencing extreme volatility and disruption. Our ability to access the capital or credit markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our flexibility to react to changing economic and business conditions. In addition, the cost of debt financing may be materially impacted by these market conditions. Accordingly, there can be no assurance that the capital and credit markets will continue to be a reliable or acceptable source of short-term or long-term financing for us. Additionally, disruptions in the capital and credit markets could have a broader impact on the economy in general in ways that could lead to reduced electricity usage, which could have a negative impact on our revenues, or have an impact on our customers, counterparties and/or lenders, causing them to fail to meet their obligations to us.
Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets and/or during times when there are significant changes in commodity prices. The inability to access liquidity, particularly on favorable terms, could materially adversely affect results of operations and/or financial condition.
Our businesses are capital intensive. We rely on access to financial markets and liquidity facilities as a significant source of liquidity for capital requirements not satisfied by cash-on-hand or operating cash flows. The inability to raise capital on favorable terms or access liquidity facilities, particularly during times of uncertainty similar to that which has recently been experienced in the financial markets, could impact our ability to sustain and grow our businesses and would likely increase capital costs. Our access to the financial markets and liquidity facilities could be adversely impacted by various factors, such as:
•
changes in financial markets that reduce available credit or the ability to obtain or renew liquidity facilities on acceptable terms;
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economic weakness in the ERCOT or general US market;
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changes in interest rates;
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a deterioration of EFH Corp.’s credit or the credit of its subsidiaries or a reduction in EFH Corp.’s or its applicable subsidiaries’ credit ratings;
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a deterioration of the credit or bankruptcy of one or more lenders or counterparties under EFH Corp.’s or its applicable subsidiaries’ liquidity facilities that affects the ability of such lender(s) to make loans to EFH Corp. or its subsidiaries;
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volatility in commodity prices that increases margin or credit requirements;
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a material breakdown in our risk management procedures, and
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the occurrence of changes in our businesses that restrict our ability to access liquidity facilities.
Although we expect to actively manage the liquidity exposure of existing and future hedging arrangements, given the size of the long-term hedging program, any significant increase in the price of natural gas could result in us being required to provide cash or letter of credit collateral in substantial amounts. While these potential posting obligations are primarily supported by the liquidity facilities, for certain transactions there is a potential for the timing of postings on the commodity contract obligations to vary from the timing of borrowings from the TCEH Commodity Collateral Posting Facility. Any perceived reduction in our credit quality could result in clearing agents or other counterparties requesting additional collateral. We have credit concentration risk related to the limited number of lenders that provide liquidity to support our hedging program. A deterioration of the credit quality of such lenders could materially affect our ability to continue such program on acceptable terms. An event of default by one or more of our hedge counterparties could result in termination-related settlement payments that reduce available liquidity if we owe amounts related to commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to us. These events could have a material negative impact on our financial condition and results of operations.
In the event that the governmental agencies that regulate the activities of our businesses determine that the creditworthiness of any such business is inadequate to support our activities, such agencies could require us to provide additional cash or letter of credit collateral in substantial amounts to qualify to do business.
In the event our liquidity facilities are being used largely to support the long-term hedging program as a result of a significant increase in the price of natural gas or significant reduction in credit quality, we may have to forego certain capital expenditures or other investments in our competitive businesses or other business opportunities.
Further, a lack of available liquidity could adversely impact the evaluation of our creditworthiness by counterparties and rating agencies. In particular, such concerns by existing and potential counterparties could significantly limit TCEH’s wholesale markets activities, including its long-term hedging program.
The costs of providing pension and OPEB and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on our results of operations and financial condition.
We provide pension benefits based on either a traditional defined benefit formula or a cash balance formula and also provide certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from us. Our costs of providing such benefits and related funding requirements are dependent upon numerous factors, assumptions and estimates and are subject to changes in these factors, assumptions and estimates, including the market value of the assets funding the pension and OPEB plans. Fluctuations in financial market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.
The substantial dislocation in the financial markets that began in 2008 caused the value of the investments that fund our pension and OPEB plans to significantly differ from, and may alter the values and actuarial assumptions we use to calculate, our projected future pension plan expense and OPEB costs. A continuation or further decline in the value of these investments could increase the expenses of the pension plan and the costs of the OPEB plans and related funding requirements in the future. Our costs of providing such benefits and related funding requirements are also subject to changing employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in financial market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.
As was the case in the fourth quarter 2008 (as discussed in Notes 1 and 3 to Financial Statements), goodwill and/or other intangible assets not subject to amortization that we have recorded in connection with the Merger are subject to at least annual impairment evaluations, and as a result, we could be required to write off some or all of this goodwill and other intangible assets, which may cause adverse impacts on our financial condition and results of operations.
In accordance with accounting standards, goodwill and certain other indefinite-lived intangible assets that are not subject to amortization are reviewed annually or more frequently for impairment, if certain conditions exist, and may be impaired. Any reduction in or impairment of the value of goodwill or other intangible assets will result in a charge against earnings, which could cause a material adverse impact on our reported results of operations and financial position.
The loss of the services of our key management and personnel could adversely affect our ability to operate our businesses.
Our future success will depend on our ability to continue to attract and retain highly qualified personnel. We compete for such personnel with many other companies, in and outside our industry, government entities and other organizations. We may not be successful in retaining current personnel or in hiring or retaining qualified personnel in the future. Our failure to attract new personnel or retain existing personnel could have a material adverse effect on our businesses.
The Sponsor Group controls and may have conflicts of interest with us in the future.
The Sponsor Group indirectly owns approximately 60% of EFH Corp.’s capital stock on a fully-diluted basis through its investment in Texas Holdings. As a result of this ownership and the Sponsor Group’s ownership in interests of the general partner of Texas Holdings, the Sponsor Group has control over decisions regarding our operations, plans, strategies, finances and structure, including whether to enter into any corporate transaction, and will have the ability to prevent any transaction that requires the approval of EFH Corp.’s shareholders.
Additionally, each member of the Sponsor Group is in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us. Members of the Sponsor Group may also pursue acquisition opportunities that may be complementary to our businesses and, as a result, those acquisition opportunities may not be available to us. So long as the members of the Sponsor Group, or other funds controlled by or associated with the members of the Sponsor Group, continue to indirectly own a significant amount of the outstanding shares of EFH Corp.’s common stock, even if such amount is less than 50%, the Sponsor Group will continue to be able to strongly influence or effectively control our decisions.
Item 1B.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
Item 3.
Item 3. LEGAL PROCEEDINGS
Litigation Related to Generation Facilities
In September 2007, an administrative appeal challenging the order of the TCEQ issuing the air permit for construction and operation of the Oak Grove generation facility in Robertson County, Texas was filed in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse the TCEQ’s approval of the Oak Grove air permit and the TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments, and remand the matter back to TCEQ for further proceedings. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before the TCEQ and the State Office of Administrative Hearings (SOAH) seeking to challenge the TCEQ’s issuance of the Oak Grove air permit and asking the District Court to remand the matter to the SOAH for further proceedings. Finally, the plaintiffs in these two additional lawsuits filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to the SOAH for further proceedings. One of the plaintiffs asked the District Court to consolidate all these proceedings, and the Attorney General of Texas, on behalf of TCEQ, filed pleas to the jurisdiction seeking dismissal of all but the administrative appeal. In May 2009, the District Court dismissed the claims that contest the merits of the TCEQ’s permitting decision, but declined to dismiss the claims that contest the process by which the TCEQ handled the permit application. Oak Grove Management Company LLC (a subsidiary of TCEH) has subsequently intervened in these proceedings and has filed its own pleas to the jurisdiction asking the court to dismiss the remaining collateral attack claims. In October 2009, one of the plaintiffs ended its legal challenge to the permit. In December 2009, the Attorney General and Oak Grove Management Company LLC filed pleadings asking the court to dismiss the administrative appeal challenging the permit for want of prosecution by the plaintiffs. In January 2010, the court denied that request and set the case for a hearing on the merits on June 16, 2010. We believe the Oak Grove air permit granted by the TCEQ was issued in accordance with applicable law. There can be no assurance that the outcome of these matters will not adversely impact the Oak Grove project.
In June and September 2008, administrative appeals were filed in the State District Court of Travis County, Texas to challenge the administrative action of the TCEQ Executive Director in issuing an air permit alteration for the previously-permitted construction and operation of the Sandow 5 generation facility in Milam County, Texas, and the failure of the TCEQ to overturn that administrative action. Plaintiffs asked that the District Court reverse the issuance of the permit alteration. The Attorney General of Texas, on behalf of TCEQ, is defending the issuance of the permit alteration. Sandow Power (a subsidiary of TCEH) intervened in support of the TCEQ. The District Court issued its ruling in November 2009 upholding the TCEQ’s issuance of the permit alteration. The plaintiffs did not appeal the court’s order by the deadline for such appeal. Thus, the matter has concluded favorably for EFH Corp.
In February 2010, the Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Big Brown generation facility. This notice is similar to the notice that Luminant received in July 2008 with respect to its Martin Lake generation facility. We cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.
In July 2008, Alcoa Inc. filed a lawsuit in the State District Court of Milam County, Texas against Luminant Generation and Luminant Mining (wholly-owned subsidiaries of TCEH), later adding EFH Corp., a number of its subsidiaries, Texas Holdings and Texas Energy Future Capital Holdings LLC as parties to the suit. The lawsuit makes various claims concerning the operation of the Sandow Unit 4 generation facility and the Three Oaks lignite mine, including claims for breach of contract, breach of fiduciary duty, fraud, tortious interference, civil conspiracy and conversion. The plaintiff requests money damages of no less than $500 million, declaratory judgment, rescission and other forms of equitable relief. An agreed scheduling order is currently in place setting trial for May 2010. While we are unable to estimate any possible loss or predict the outcome of this litigation, we believe the plaintiff’s claims made in this litigation are without merit and, accordingly, intend to vigorously defend this litigation.
Regulatory Investigations and Reviews
In June 2008, the EPA issued a request for information to TCEH under EPA’s authority under Section 114 of the Clean Air Act. The stated purpose of the request is to obtain information necessary to determine compliance with the Clean Air Act, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received a large and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently received a notice of violation from the EPA, which has in some cases progressed to litigation or settlement. The company is cooperating with the EPA and is responding in good faith to the EPA’s request, but is unable to predict the outcome of this matter.
Other Proceedings
In addition to the above, we are involved in various other legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect on our financial position, results of operations or cash flows.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
Item 5.
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
As a result of the Merger, EFH Corp.’s common stock is privately held, and there is no established public trading market for EFH Corp.’s common stock.
See Note 14 to Financial Statements for a description of the restrictions on EFH Corp.’s ability to pay dividends.
The number of holders of the common stock of EFH Corp. as of February 18, 2010 was 117.
Item 6.
Item 6. SELECTED FINANCIAL DATA
EFH CORP. AND SUBSIDIARIES
SELECTED FINANCIAL DATA
(millions of dollars, except ratios)
See Notes to Financial Statements.
EFH CORP. AND SUBSIDIARIES
SELECTED FINANCIAL DATA (CONTINUED)
(millions of dollars, except ratios)
(a) Fixed charges exceeded “earnings” (net loss) by $10.469 billion and $2.034 billion for the year ended December 31, 2008 and for the period from October 11, 2007 through December 31, 2007, respectively.
(b) Represents the annual interest using year-end rates for variable rate debt and reflecting the effects of interest rate swaps (excluding unrealized mark-to-market gains or losses) and amortization of any discounts, premiums, issuance costs and any deferred gains/losses on reacquisitions divided by the carrying value of the debt plus or minus the unamortized balance of any discounts, premiums, issuance costs and gains/losses on reacquisitions at the end of the year.
(c) Preferred stock outstanding at the end of 2008, 2007, 2006 and 2005 has a stated amount of $51 thousand. There was no outstanding preferred stock at the end of 2009.
Note: Although EFH Corp. continued as the same legal entity after the Merger, its “Selected Financial Data” for periods preceding the Merger and for periods succeeding the Merger are presented as the consolidated financial statements of the “Predecessor” and the “Successor,” respectively. See Note 1 to Financial Statements “Basis of Presentation.” The consolidated financial statements of the Successor reflect the application of “purchase accounting.” Results for 2008 were significantly impacted by impairment charges related to goodwill, trade name and emission allowances intangible assets and natural gas-fueled generation facilities.
Quarterly Information (Unaudited)
Results of operations by quarter are summarized below. In our opinion, all adjustments (consisting of normal recurring accruals) necessary for a fair statement of such amounts have been made. Quarterly results are not necessarily indicative of a full year’s operations because of seasonal and other factors. All amounts are in millions of dollars.
(a) Net income (loss) amounts include the effects of impairment charge related to goodwill (see Note 3 to Financial Statements).
(b) Net income (loss) amounts include the effects of impairment charge related to emission allowances intangible assets (see Note 3 to Financial Statements).
(c) Net income (loss) amounts include the effects of impairment charges related to goodwill, trade name and emission allowances intangible assets and natural gas-fueled generation facilities (see Notes 3 and 5 to Financial Statements).
Item 7.
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations for the fiscal years ended December 31, 2009, 2008 and 2007 should be read in conjunction with Selected Financial Data and our audited consolidated financial statements and the notes to those statements.
All dollar amounts in the tables in the following discussion and analysis are stated in millions of US dollars unless otherwise indicated.
BUSINESS
We are a Dallas-based holding company conducting operations principally through our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority-owned (approximately 80%) subsidiary engaged in regulated electricity transmission and distribution operations in Texas. Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor. See Note 1 to Financial Statements for a description of the material features of these “ring-fencing” measures and Note 15 to Financial Statements for discussion of noncontrolling interests sold by Oncor.
Operating Segments
We have aligned and report our business activities as two operating segments: the Competitive Electric segment and the Regulated Delivery segment. The Competitive Electric segment is principally comprised of TCEH. The segment also includes equipment salvage and resale activities related to the cancellation of the development of eight new coal-fueled generation units in 2007. The Regulated Delivery segment is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary.
See Note 24 to Financial Statements for further information regarding reportable business segments.
Significant Activities and Events
Long-Term Hedging Program - TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, the company has entered into market transactions involving natural gas-related financial instruments, and as of December 31, 2009, has effectively sold forward approximately 1.6 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 200,000 GWh at an assumed 8.0 market heat rate) for the period from January 1, 2010 through December 31, 2014 at weighted average annual hedge prices ranging from $7.80 per MMBtu to $7.19 per MMBtu. These transactions, as well as forward power sales, have effectively hedged an estimated 68% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning January 1, 2010 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices, which is expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If the correlation changes in the future, the cash flows targeted under the long-term hedging program may not be achieved.
The long-term hedging program is comprised primarily of contracts with prices based on the New York Mercantile Exchange (NYMEX) Henry Hub pricing point. However, because there are other local and regional natural gas pricing points such as Houston Ship Channel, future wholesale power prices in ERCOT may not correlate as closely to the Henry Hub pricing as other pricing points, which could decrease the effectiveness of the positions in the long-term hedging program in mitigating power price exposure. The company has hedged more than 95% of the Houston Ship Channel versus Henry Hub pricing point risk for 2010.
The company has entered into related put and call transactions (referred to as collars), primarily for year 2014 of the program, that effectively hedge natural gas prices within a range. These transactions represented approximately 6% of the positions in the long-term hedging program at December 31, 2009, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu. The company expects to use financial instruments, including collars, in future hedging activity under the long-term hedging program.
The following table summarizes the natural gas hedges in the long-term hedging program as of December 31, 2009:
(a) Where collars are reflected, the volumes are estimated based on the natural gas price sensitivity (i.e., delta position) of the derivatives. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 97 million MMBtu in 2014.
(b) Weighted average hedge prices are based on NYMEX Henry Hub prices of forward natural gas sales positions in the long-term hedging program (excluding the impact of offsetting purchases for rebalancing and pricing point basis transactions). Where collars are reflected, sales price represents the collar floor price.
(c) Based on NYMEX Henry Hub prices.
Changes in the fair value of the instruments in the long-term hedging program are being recorded as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities in the statement of income, which has and could continue to result in significant volatility in reported net income. Based on the size of the long-term hedging program as of December 31, 2009, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $1.6 billion in pretax unrealized mark-to-market gains or losses.
The reported unrealized mark-to-market net gain related to the long-term hedging program for the year ended December 31, 2009 totaled $1.107 billion. This amount reflects a $1.857 billion net gain due to the effect of lower forward prices of natural gas on the value of positions in the program, which was partially offset by net losses of $750 million representing reversals of previously recorded unrealized gains on positions that settled in the period. The reported unrealized mark-to-market net gain related to the long-term hedging program for the year ended December 31, 2008 totaled $2.587 billion reflecting declines in forward prices of natural gas in 2008. Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains or losses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If natural gas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricity prices and will in this context be viewed as having resulted in an opportunity cost. The cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program totaled $1.978 billion and $871 million at December 31, 2009 and December 31, 2008, respectively. These values can change materially as market conditions change.
As of December 31, 2009, more than 95% of the long-term hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility - see discussion below under “Financial Condition - Liquidity and Capital Resources”) thereby reducing the cash and letter of credit collateral requirements for the hedging program.
See “Key Risks and Challenges - Substantial Leverage, Uncertain Financial Markets and Liquidity Risk” and “ - Natural Gas Price and Market Heat Rate Exposure.”
Debt Exchanges and Issuances - See Note 12 to Financial Statements for discussion of debt exchange offers completed in November 2009 and the issuance of additional notes in January 2010.
TCEH Interest Rate Swap Transactions - As of December 31, 2009, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $16.30 billion principal amount of its senior secured debt maturing from 2010 to 2014. All of these swaps were entered into prior to January 1, 2009. Taking into consideration these swap transactions, approximately 10% of our total long-term debt portfolio at December 31, 2009 was exposed to variable interest rate risk. TCEH also entered into interest rate basis swap transactions, which further reduce the fixed (through swaps) borrowing costs, related to an aggregate of $16.25 billion principal amount of senior secured debt. We may enter into additional interest rate hedges from time to time. Unrealized mark-to-market net gains and losses related to all TCEH interest rate swaps, which are reported in interest expense and related charges, totaled $696 million in net gains for the year ended December 31, 2009 and $1.477 billion in net losses for the year ended December 31, 2008. The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.212 billion and $1.909 billion at December 31, 2009 and 2008, respectively, of which $194 million and $364 million (both pre-tax), respectively, was reported in accumulated other comprehensive income. These fair values can change materially as market conditions change, which could result in significant volatility in reported net income. See discussion in Note 12 to Financial Statements regarding various interest rate swap transactions.
Texas Generation Facilities Development - TCEH is nearing completion of a program to develop three lignite-fueled generation units (2 units at Oak Grove and 1 unit at Sandow) in Texas with a total estimated capacity of approximately 2,200 MW. The Sandow unit and the first Oak Grove unit achieved substantial completion (as defined in the EPC Agreements for the units) effective September 30, 2009 and December 22, 2009, respectively. Accordingly, the company has operational control of these units. We began depreciating these units and recognizing revenues and fuel costs for accounting purposes in the fourth quarter 2009. The second Oak Grove unit, which is in the commissioning and start-up phase, synchronized to the grid in January 2010 and is expected to achieve substantial completion (as defined in the EPC Agreement for the unit) in mid-2010. Aggregate cash capital expenditures for these three units are expected to total approximately $3.25 billion including all construction, site preparation and mining development costs, of which approximately $3.1 billion was spent as of December 31, 2009. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, are expected to total approximately $4.8 billion upon completion of the units, and the balance was $4.6 billion as of December 31, 2009. See discussion in Note 13 to Financial Statements regarding contingencies related to these units.
Nuclear Generation Development - In September 2008, a subsidiary of TCEH filed a combined operating license application with the NRC for two new nuclear generation units, each with approximately 1,700 MW (gross capacity), at its existing Comanche Peak nuclear generation site. In connection with the filing of the application, in January 2009, subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, Comanche Peak Nuclear Power Company (CPNPC), to further the development of the two new nuclear generation units using MHI’s US-Advanced Pressurized Water Reactor technology. The TCEH subsidiary owns an 88% interest in CPNPC, and a MHI subsidiary owns a 12% interest.
In March 2009, the NRC announced an official review schedule for the license application. Based on the schedule, the NRC expects to complete its review by December 2011, and it is expected that a license would be issued approximately one year later. In November 2009, CPNPC filed a comprehensive revision to the license application that updated the license application for developments occurring after the initial filing.
In 2009, the DOE announced that it had selected four applicants to proceed to the due diligence phase of its Loan Guarantee Program, and to commence negotiations towards potential loan guarantees for their respective generation projects. CPNPC was not among the initial four applicants selected by the DOE; however, CPNPC continues to update the DOE on its progress, with the goal of securing a DOE loan guarantee for financing the proposed units prior to commencement of construction.
Idling of Natural Gas-Fueled Units - In February 2009, we notified ERCOT of plans to retire 11 of our natural gas-fueled units, totaling 2,251 MW of capacity (2,341 MW installed nameplate capacity), in May 2009, and mothball (idle) an additional four units, totaling 1,651 MW of capacity (1,675 MW of installed nameplate capacity), in September 2009. In May and September 2009, we entered into reliability-must-run (RMR) agreements for the remainder of 2009 with ERCOT for the operation of one unit originally planned to be retired with 112 MW of capacity (115 MW of installed nameplate capacity) and one unit planned to be mothballed with 515 MW of capacity (540 MW of installed nameplate capacity), respectively. In December 2009, we entered into RMR agreements with ERCOT for these same two units for January through November 2010. The other units were retired in May 2009 or mothballed in September 2009 as originally planned. An impairment charge of $229 million related to the carrying value of these units was recorded in the fourth quarter of 2008.
Global Climate Change - See Items 1 and 2 “Business and Properties - Environmental Regulations and Related Considerations” for discussion of global climate change and the effects on the company.
Impairment of Goodwill - Financial market conditions had a significant effect on our 2008 assessment of the carrying value of goodwill. We recorded a total goodwill impairment charge of $8.950 billion (which was not deductible for income tax purposes) in 2008 and 2009, primarily arising from the dislocation in the capital markets that had increased interest rate spreads and the resulting discount rates used in estimating fair values and the effects of declines in market values of debt and equity securities of comparable companies.
This non-cash impairment did not cause EFH Corp. or its subsidiaries to be in default under any of their respective debt covenants or impact counterparty trading agreements or have a material impact on liquidity.
See Note 3 to Financial Statements and “Application of Critical Accounting Policies” below for more information on the goodwill impairment charge.
Oncor Technology Initiatives - Oncor continues to invest in technology initiatives that include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is expected to produce electricity service reliability improvements and provide the potential for additional products and services from REPs that will enable businesses and consumers to better manage their electricity usage and costs. Oncor’s plans provide for the full deployment of over three million advanced meters by the end of 2012 to all residential and most non-residential retail electricity customers in Oncor’s service area. The advanced meters can be read remotely, rather than by a meter reader physically visiting the location of each meter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amount of electricity they are consuming and adjust their electricity consumption habits.
As of December 31, 2009, Oncor has installed approximately 660 thousand advanced digital meters, including approximately 620 thousand during the year ended December 31, 2009. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $196 million as of December 31, 2009.
As discussed below under “Regulation and Rates,” Oncor has implemented a rate surcharge effective January 1, 2009 to recover its investment in the advanced meter deployment.
Oncor Matters with the PUCT - See discussion of these matters, including the awarded construction of $1.3 billion of transmission lines and a rate case with the PUCT, below under “Regulation and Rates.”
KEY RISKS AND CHALLENGES
Following is a discussion of key risks and challenges facing management and the initiatives currently underway to manage such challenges.
Substantial Leverage, Uncertain Financial Markets and Liquidity Risk
Our substantial leverage, resulting in large part from debt incurred to finance the Merger, requires significant cash flows to be dedicated to interest and principal payments and could adversely affect our ability to raise additional capital to fund operations, limit our ability to react to changes in the economy, our industry or our business, and expose us to interest rate risk to the extent not hedged. Short-term borrowings and long-term debt, including amounts due currently, totaled $43.426 billion at December 31, 2009. Taking into consideration interest-rate swap transactions, as of December 31, 2009 approximately 90% of our total long-term debt portfolio is subject to fixed interest rates, at a weighted average interest rate of 8.95%. Interest payments on long-term debt in 2010 are expected to total approximately $3.059 billion, and principal payments are expected to total approximately $340 million.
While we believe our cash on hand and cash flow from operations combined with availability under existing credit facilities provide sufficient liquidity to fund current and projected expenses and capital requirements for 2010 (see “Financial Condition - Liquidity and Capital Resources” section below), there can be no assurance that counterparties to our credit facilities will perform as expected through the maturity dates or hedging and trading counterparties, particularly related to the long-term hedging program, will meet their obligations to us. Failure of such counterparties to meet their obligations or substantial changes in financial markets, the economy, the requirements of regulators or our industry or operations could result in constraints in our liquidity. See discussion of credit risk in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” and discussion of credit facilities in “Financial Condition - Liquidity and Capital Resources” and in Note 12 to Financial Statements. Also, as a result of the financial crisis that arose in 2008, there has been a reduction of available counterparties for our hedging and trading activities, particularly for longer-dated transactions, which could impact our ability to hedge our commodity price and interest rate exposure to desired levels at reasonable costs. However, traditional counterparties with physical assets to hedge, as well as financial institutions and other parties, continue to participate in the markets.
A substantial amount of our indebtedness is scheduled to mature in the period from 2014 through 2017. We are focused on improving the balance sheet and expect to opportunistically look for ways to reduce the amount and extend the weighted average maturity of our outstanding debt. Progress to date on this initiative includes the August 2009 amendment to the Credit Agreement governing the TCEH Senior Secured Facilities that provides additional flexibility in restructuring debt obligations, the debt exchanges completed in November 2009 and the January 2010 issuance of $500 million of senior secured notes to be used for general corporate purposes, including but not limited to, repurchase of outstanding indebtedness. See Note 12 to Financial Statements for additional discussion of these transactions.
In addition, because our operations are capital intensive, we expect to rely over the long-term upon access to financial markets as a significant source of liquidity for capital requirements not satisfied by cash-on-hand, operating cash flows or our available credit facilities. Our ability to economically access the capital or credit markets could be restricted at a time when we would like, or need, to access those markets. Lack of such access could have an impact on our flexibility to react to changing economic and business conditions.
Natural Gas Price and Market Heat-Rate Exposure
Wholesale electricity prices in the ERCOT market generally move with the price of natural gas because marginal demand for electricity supply is generally met with natural gas-fueled generation facilities. Historically the price of natural gas has fluctuated due to the effects of weather, changes in industrial demand, supply availability, and other economic and market factors and such prices have been very volatile in recent years. Since 2005, forward natural gas prices ranged from below $4 per MMBtu to above $13 per MMBtu. The wholesale market price of power divided by the market price of natural gas represents the market heat rate. Market heat rate movements also affect wholesale electricity prices. Market heat rate reflects the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) in generating electricity.
In contrast to our natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating electricity from our nuclear and lignite/coal-fueled plants. All other factors being equal, these baseload generation assets, which provided 70% of supply volumes in 2009, increase or decrease in value as natural gas prices and market heat rates rise or fall, respectively, because of the effect of natural gas prices setting marginal wholesale power prices in ERCOT.
With the exposure to variability of natural gas prices, retail sales price management and hedging activities are critical to the profitability of the business and maintaining consistent cash flow levels.
Our approach to managing commodity price risk focuses on the following:
•
employing disciplined hedging and risk management strategies through physical and financial energy-related (electricity and natural gas) contracts intended to partially hedge gross margins;
•
continuing reduction of fixed costs to better withstand gross margin volatility;
•
following a retail pricing strategy that appropriately reflects the magnitude and costs of commodity price and liquidity risk, and
•
improving retail customer service to attract and retain high-value customers.
As discussed above under “Significant Activities and Events,” we have implemented a long-term hedging program to mitigate the risk of future declines in wholesale electricity prices due to declines in natural gas prices.
The following sensitivity table provides estimates of the potential impact (in $millions) of movements in natural gas and certain other commodity prices and market heat rates on realized pre-tax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH’s unhedged position and forward prices as of December 31, 2009, which for natural gas reflects estimates of electricity generation less amounts hedged through the long-term natural gas hedging program and amounts under existing wholesale and retail sales contracts. On a rolling twelve-month basis, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.
(a) Balance of 2010 is from February 1, 2010 through December 31, 2010.
(b) Assumes conversion of electricity positions based on an approximate 8.0 market heat rate with natural gas being on the margin 75% to 90% of the time (i.e., when coal is forecast to be on the margin, no natural gas position is assumed to be generated).
(c) Based on Houston Ship Channel natural gas prices as of December 31, 2009.
Our market heat rate exposure is impacted by changes in the mix of generation assets, such as generation capacity increases, particularly increases in lignite/coal- and nuclear-fueled generation capacity, as well as wind capacity, which could result in lower market heat rates. We expect that decreases in market heat rates would decrease the value of our generation assets because lower market heat rates generally result in lower wholesale electricity prices, and vice versa. We mitigate market heat rate risk through retail and wholesale electricity sales contracts and shorter-term market heat rate hedging transactions. We evaluate opportunities to mitigate market heat rate risk over extended periods through longer-term electricity sales contracts where practical considering pricing, credit, liquidity and related factors.
On an ongoing basis, we will continue monitoring our overall commodity risks and seek to balance our portfolio based on our desired level of exposure to natural gas prices and market heat rates and potential changes to our operational forecasts of overall generation and consumption (which is also subject to volatility resulting from customer churn, weather, economic and other factors) in our native and growth business. Portfolio balancing may include the execution of incremental transactions, including heat rate hedges, the unwinding of existing transactions and the substitution of natural gas hedges with commitments for the sale of electricity at fixed prices. As a result, commodity price exposures and their effect on earnings could materially change from time to time.
The Obama Administration has proposed financial market reforms with respect to the currently unregulated Over-the-Counter (OTC) financial derivatives market. As a result, the US House of Representative has approved a bill to regulate OTC derivatives. The bill would require certain entities to clear OTC derivatives that are currently traded on the bilateral market through exchanges, which require that all collateral be in the form of cash. We have entered into a significant number of asset-backed OTC derivatives to hedge risks associated with commodity and interest rate exposure. The US House of Representatives legislation would not require us to clear our OTC derivatives through exchanges. However, other proposals would have required such clearing, and it is not evident what, if any, US Senate legislation might be approved. If we were required to clear such transactions, we would likely be precluded from using our noncash assets as collateral for hedging arrangements. This preclusion could have a material impact on our liquidity, particularly if the final legislation does not provide for the grandfathering of existing OTC derivatives. As a result, if applied to our OTC derivatives transactions, legislation that impairs the use of asset-backed transactions could significantly increase our costs of entering into OTC derivatives and/or could significantly limit our ability to enter into OTC derivatives and hedge our commodity and interest rate risks. We cannot predict whether or when final legislation will be enacted or whether the US House of Representatives bill exemptions will be included in any final legislation.
See “Financial Condition - Liquidity and Capital Resources” below for a discussion of the liquidity effects of the long-term hedging program. Also see additional discussion of risk below under Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.”
Competitive Retail Markets and Customer Retention
Competitive retail activity in Texas has resulted in some volatility in retail customer counts. Total retail customer counts decreased less than 1% in 2007, rose 2% in 2008 and declined 3% in 2009. In responding to the competitive landscape in the ERCOT marketplace, we are focusing on the following key initiatives:
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Maintaining competitive pricing initiatives as evidenced by price reductions on most residential service plans in 2008 and 2009, in addition to the 15% cumulative price reduction in 2007 applicable to residential customers under qualifying service plans;
•
Profitably growing the retail customer base by actively competing for new and existing customers in areas in Texas open to competition. The customer retention strategy remains focused on continuing to implement initiatives to deliver world-class customer service and improve the overall customer experience;
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Establishing TXU Energy as the most innovative retailer in the Texas market by continuing to develop tailored product offerings to meet customer needs. TXU Energy plans to invest $100 million over the five-year period beginning in 2008 (including $20 million invested through 2009) in retail initiatives aimed at helping consumers conserve energy and other demand-side management initiatives that are intended to moderate consumption and reduce peak demand for electricity, and
•
Focusing business market initiatives largely on programs targeted to retain the existing highest-value customers and to recapture customers who have switched REPs. Initiatives include maintaining and continuously refining a disciplined contracting and pricing approach and economic segmentation of the business market to enhance targeted sales and marketing efforts and to more effectively deploy the direct-sales force. Tactical programs put into place include improved customer service, aided by a new customer management system implemented in 2009, the successful operation of which is critical to customer satisfaction, new product price/service offerings and a multichannel approach for the small business market.
Volatile Energy Prices and Regulatory Risk
Natural gas prices rose to unprecedented levels in the latter part of 2005, reflecting a world-wide increase in energy prices compounded by hurricane-related infrastructure damage. The related rise in electricity prices elevated public awareness of energy costs and dampened customer demand. Natural gas prices remain subject to events that create price volatility, and while not reaching 2005 levels, forward natural gas prices rose substantially in 2007 and part of 2008 before falling in the second half of 2008 and continuing to fall through most of 2009. Sustained high energy prices and/or ongoing price volatility also creates a risk for regulatory and/or legislative intervention with the mechanisms that govern the competitive wholesale and retail markets in ERCOT. We believe that competitive markets result in a broad range of innovative pricing and service alternatives to consumers and ultimately the most efficient use of resources and regulatory entities should continue to take actions that encourage competition in the industry. Regulatory and/or legislative intervention could disrupt the relationship between natural gas prices and electricity prices, which could impact the results of our long-term hedging strategy and our results of operations.
New and Changing Environmental Regulations
We are subject to various environmental laws and regulations related to SO2, NOx and mercury emissions as well as other environmental contaminants that impact air and water quality. We are in compliance with all current laws and regulations, but regulatory authorities continue to evaluate existing requirements and consider proposals for changes. We continue to closely monitor any potential legislative and regulatory changes pertaining to global climate change. In view of the fact that a substantial portion of our generation portfolio consists of lignite/coal-fueled generation facilities, our financial condition or results of operations could be materially adversely affected by the enactment of any legislation, regulation or judicial action that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes on entities that produce GHG emissions. For example, federal, state or regional legislation or regulation addressing global climate change could result in us either incurring increased material costs to reduce our GHG emissions or to procure emission allowances or credits to comply with a mandatory cap-and-trade emissions reduction program or incurring increased taxes, which could be material, due to the imposition of a carbon tax. See further discussion under Items 1 and 2, “Business and Properties - Environmental Regulations and Related Considerations.”
Exposures Related to Nuclear Asset Outages
Our nuclear assets are comprised of two generation units at Comanche Peak, each with an installed nameplate capacity of 1,150 MW. The Comanche Peak plant represents approximately 13% of our total generation capacity. The nuclear generation units represent our lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage, the unfavorable impact to pretax earnings is estimated to be approximately $2 million per day before consideration of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 13 to Financial Statements.
The inherent complexities and related regulations associated with operating nuclear generation facilities result in environmental, regulatory and financial risks. The operation of nuclear generation facilities is complex and subject to continuing review and regulation by the NRC, covering, among other things, operations, maintenance, emergency planning, security, and environmental and safety protection. The NRC may implement changes in regulations that result in increased capital or operating costs, and it may require extended outages, modify, suspend or revoke operating licenses and impose fines for failure to comply with its existing regulations and the provisions of the Atomic Energy Act. In addition, an unplanned outage at another nuclear generation facility could result in the NRC taking action to shut down the Comanche Peak plant as a precautionary measure.
The Comanche Peak plant has not experienced an extended unplanned outage, and management continues to focus on the safe, reliable and efficient operations at the plant.
Other Matters
See Note 13 to Financial Statements for discussion of litigation related to our new lignite-fueled generation facility construction program and “Regulation and Rates” for discussion of ERCOT’s planned implementation of a nodal market.
APPLICATION OF CRITICAL ACCOUNTING POLICIES
Our significant accounting policies are discussed in Note 1 to Financial Statements. We follow accounting principles generally accepted in the US. Application of these accounting policies in the preparation of our consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and revenues and expenses during the periods covered. The following is a summary of certain critical accounting policies that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.
Purchase Accounting
In 2007, the Merger was accounted for under purchase accounting, whereby the purchase price of the transaction was allocated to our identifiable assets acquired and liabilities assumed based upon their fair values. The estimates of the fair values recorded were determined based on the principles in accounting standards related to the determination of fair value (see Note 16 to Financial Statements) and reflect significant assumptions and judgments. Material valuation inputs for long-lived assets and liabilities included forward electricity and natural gas price curves and market heat rates, discount rates, nonperformance risk adjustments related to liabilities, retail customer attrition rates, generation plant operating and construction costs and asset lives. The valuations reflected considerations unique to the competitive wholesale power market in ERCOT as well as our assets. For example, the valuation of the baseload generation facilities considered our lignite fuel reserves and mining capabilities.
The results of the purchase price allocation included an increase in the total carrying value of our baseload generation plants and the recording of intangible assets related to the retail customer base, the TXU Energy trade name and emission credits. Further, commodity and other contracts not already subject to fair value accounting were valued, and amounts representing favorable or unfavorable contracts (versus market conditions as of the date of the Merger) were recorded as intangible assets or liabilities, respectively. Management believes all material intangible assets were identified. See Notes 2 and 3 to Financial Statements for details of the purchase price allocation and intangible assets recorded, respectively.
With respect to Oncor, the realization of its assets and settlement of its liabilities are largely subject to cost-based regulatory rate-setting processes. Accordingly, the historical carrying values of a majority of Oncor's assets and liabilities are deemed to represent fair values. See discussion in Note 25 to Financial Statements regarding adjustments to the carrying values of Oncor’s regulatory asset and related long-term debt.
The excess of the purchase price over the estimated fair values of the net assets acquired was recorded as goodwill. The goodwill amount recorded upon finalization of purchase accounting totaled $23.2 billion. Management believes the drivers of the goodwill amount included the incremental value of the future cash flow potential of the baseload generation facilities, including facilities under construction, over the values assigned to those assets under purchase accounting rules, considering the market-pricing mechanisms and growth potential in the ERCOT market, as well as the value derived from the scale of the retail business. Management also believes that the goodwill reflected the value of the relatively stable, long-lived cash flows of the regulated business, considering the constructive regulatory environment and market growth potential. In accordance with accounting guidance related to goodwill and other intangible assets, goodwill is not amortized to net income, but is required to be tested for impairment at least annually. This guidance requires that goodwill be assigned to “reporting units,” which management has determined to be the Competitive Electric segment and the Regulated Delivery segment, which are almost entirely comprised of TCEH and Oncor, respectively. The assignment of goodwill was based on the relative estimated enterprise values of the operations as of the date of the Merger using discounted cash flow methodologies. Goodwill amounts assigned totaled $18.3 billion to the Competitive Electric segment and $4.9 billion to the Regulated Delivery segment. None of this goodwill balance is being deducted for tax purposes.
In the first quarter of 2009 and fourth quarter of 2008, we recorded goodwill impairment charges totaling $8.950 billion. The $90 million charge in the first quarter of 2009 resulted from the completion of the previously estimated fair value calculations supporting the initial $8.860 billion goodwill impairment charge that was recorded in the fourth quarter of 2008. See discussion immediately below under “Impairment of Assets.”
Impairment of Assets
We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist, in accordance with accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. One of those indications is a current expectation that “more likely than not” a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life (as was the case for the natural gas-fueled generation assets discussed below). For our baseload generation assets, another possible indication would be an expected long-term decline in natural gas prices and/or market heat rates. The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows related to an asset or group of assets. Further, the unique nature of our property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual plants that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing.
Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually or whenever events or changes in circumstances indicate an impairment may exist, such as the possible impairments to long-lived assets discussed above. Effective with 2009 testing, we changed the annual test date for goodwill and intangible assets with indefinite useful lives from October 1 to December 1. Management determined the new annual goodwill test date is preferable because of efficiencies gained by aligning the test with our annual budget and five-year plan processes in the fourth quarter. The change in the annual test date did not delay, accelerate or avoid an impairment charge, and retrospective application of this change in accounting principle did not affect previously reported results. As required by accounting guidance related to goodwill and other intangible assets, we have allocated goodwill to our reporting units, which are our two segments: Competitive Electric and Regulated Delivery, and goodwill impairment testing is performed at the reporting unit level. Under this goodwill impairment analysis, if at the assessment date, a reporting unit’s carrying value exceeds its estimated fair value (enterprise value), the estimated enterprise value of the reporting unit is compared to the estimated fair values of the reporting unit’s operating assets (including identifiable intangible assets) and liabilities at the assessment date, and the resultant implied goodwill amount is then compared to the recorded goodwill amount. Any excess of the recorded goodwill amount over the implied goodwill amount is written off as an impairment charge.
The determination of enterprise value involves a number of assumptions and estimates. We use a combination of three fair value inputs to estimate enterprise values of our reporting units: internal discounted cash flow analyses (income approach), comparable company equity values and any recent pending and/or completed relevant transactions. The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, generation plant performance and retail sales volume trends. Another key variable in the income approach is the discount rate, or weighted average cost of capital. The determination of the discount rate takes into consideration the capital structure, debt ratings and current debt yields of comparable companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry. Enterprise value estimates based on comparable company equity values involve using trading multiples of EBITDA of those selected companies to derive appropriate multiples to apply to the EBITDA of the reporting units. This approach requires an estimate, using historical acquisition data, of an appropriate control premium to apply to the reporting unit values calculated from such multiples. Critical judgments include the selection of comparable companies and the weighting of the three value inputs in developing the best estimate of enterprise value.
The 2009 annual impairment testing performed as of October 1, and December 1, 2009 for goodwill and intangible assets with indefinite useful lives in accordance with accounting guidance for a change in annual impairment testing dates resulted in no impairment (see discussion in Note 1 to Financial Statements regarding change in the annual impairment test date from October 1 to December 1). The goodwill testing determined that the estimated fair value (enterprise value) of the Regulated Delivery segment exceeded its carrying value by approximately 10% resulting in no additional testing being required and no impairment for the segment. Key assumptions in the valuation of the regulated business include discount rates, growth of the rate base and return on equity allowed by the regulatory authority. Cash flows of the regulated business are relatively stable and more predictable than the competitive business. The Competitive Electric segment carrying value exceeded its estimated enterprise value (by less than 10%), so the estimated enterprise value of the segment was compared to the estimated fair values of its operating assets and liabilities. This additional testing indicated that the implied goodwill amount exceeded the recorded goodwill amount, and thus no goodwill impairment was recorded. The estimated enterprise value of the Competitive Electric segment reflects the impact of the decline in forward natural gas prices on wholesale electricity prices. Because lower wholesale electricity prices also result in lower fair values of our generation assets, calculated implied goodwill was sufficient to support the recorded goodwill amount. Key variables in the tests included forward natural gas prices, electricity prices, market heat rates and discount rates, assumptions regarding each of which could have a significant effect on valuations. Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.
See Note 3 to Financial Statements for a discussion of the goodwill impairment charges of $8.860 billion and $90 million (not deductible for income tax purposes) recorded in the fourth quarter of 2008 and first quarter of 2009, respectively. The total $8.950 billion impairment charge represented approximately 39% of the goodwill balance resulting from purchase accounting for the Merger and reflected a decline of approximately 20% in the estimated value of EFH Corp. at year-end 2008 from the indicated value at the October 2007 Merger date. The impairment primarily arose from the dislocation in the capital markets that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies in the second half of 2008. Also see Note 3 to Financial Statements for discussion of the impairment charge of $481 million ($310 million after-tax) related to the trade name intangible asset also recorded in the fourth quarter of 2008. The estimated fair value of this intangible asset is based on an assumed royalty methodology.
In the fourth quarter of 2008, we recorded an impairment charge of $229 million ($147 million after-tax) related to our natural gas-fueled generation facilities. The natural gas-fueled generation units are generally operated to meet peak demands for electricity, and the facilities tested for impairment as an asset group. See Note 5 to Financial Statements for a discussion of the impairment. The estimated impairment was based on numerous judgments including forecasted production, forward prices of natural gas and electricity, overall generation availability in ERCOT and ERCOT grid congestion. See “Business - Significant Activities and Events” for discussion of natural gas-fueled units mothballed (idled) or retired in 2009 consistent with the factors that resulted in the impairment.
In 2007, we recorded a net charge totaling $757 million ($492 million after-tax) (substantially all of which was in the Predecessor period) in connection with the 2007 suspension and subsequent cancellation of the development of eight coal-fueled generation units. This decision and subsequent terminations of equipment orders required an evaluation and substantial judgments regarding the recoverability of recorded assets associated with the development program. In determining the net charges recorded, we applied accounting rules for impairment of long-lived assets under guidance related to impairment or disposal of long-lived assets and for exit activities under guidance related to accounting for costs associated with exit or disposal activities. See Note 4 to Financial Statements for additional discussion.
Derivative Instruments and Mark-to-Market Accounting
We enter into contracts for the purchase and sale of energy-related commodities, and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. Under accounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation techniques.
Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using modeling techniques that take into account available market information and other inputs that might not be readily observable in the market. We adopted new accounting standards related to the determination of fair value concurrent with the Merger and estimate fair value as described in Note 16 to Financial Statements and discussed under “Fair Value Measurements” below.
Accounting standards related to derivative instruments and hedging activities allow for “normal” purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. These elections and designations are intended to match the accounting recognition of the contract's financial performance to that of the transaction the contract is intended to hedge. “Normal” purchases and sales are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are not subject to mark-to-market accounting.
Under hedge accounting, changes in fair value of instruments designated as cash flow hedges are recorded in other comprehensive income with an offset to derivative assets and liabilities to the extent the change in value is effective; that is, it mirrors the offsetting change in fair value of the forecasted hedged transaction. Changes in value that represent ineffectiveness of the hedge are recognized in net income immediately, and the effective portion of changes in fair value initially recorded in other comprehensive income are recognized in net income in the period that the hedged transactions are recognized. Although as of December 31, 2009, we do not have any derivatives designated as cash flow or fair value hedges, we continually assess our hedge elections and could designate positions as cash flow hedges in the future. In March 2007, the instruments making up a significant portion of the long-term hedging program that were previously designated as cash flow hedges were dedesignated as allowed under accounting standards related to derivative instruments and hedging activities, and subsequent changes in their fair value are being marked-to-market in net income. In addition, in August 2008, interest rate swap transactions in effect at that time were dedesignated as cash flow hedges in accordance with accounting standards, and subsequent changes in their fair value are being marked-to-market in net income. See further discussion of the long-term hedging program and interest rate swap transactions above under “Business - Significant Activities and Events.”
The following tables provide the effects on both net income and other comprehensive income of mark-to-market accounting for those derivative instruments that we have determined to be subject to fair value measurement under accounting standards related to derivative instruments and hedging activities.
(a) Amounts for 2009 and 2008 include $788 million and $1.503 billion in net after-tax gains related to commodity positions, respectively, and $452 million in net after-tax gains and $960 million in net after-tax losses related to interest rate swaps, respectively. Prior period amounts are essentially all related to commodity positions.
The effect of mark-to-market and hedge accounting for derivatives on the balance sheet is as follows:
Fair Value Measurements
In addition to purchase accounting, we apply fair value accounting on a recurring basis to certain assets and financial instruments under the fair value hierarchy established in accounting standards related to the determination of fair value. We utilize several valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These techniques include, but are not limited to, the use of broker quotes and statistical relationships between different price curves and are intended to maximize the use of observable inputs and minimize the use of unobservable inputs. In applying the market approach, we use a mid-market valuation convention (the mid-point between bid and ask prices) as a practical expedient.
Level 1 and Level 2 assets and liabilities consist primarily of commodity-related contracts for natural gas and electricity derivative instruments entered into for hedging purposes, securities associated with the nuclear decommissioning trust, and interest rate swaps intended to fix and/or lower interest payments on long-term debt. Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Level 2 valuations are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences. Level 2 inputs include:
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quoted prices for similar assets or liabilities in active markets;
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quoted prices for identical or similar assets or liabilities in markets that are not active;
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inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals, and
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inputs that are derived principally from or corroborated by observable market data by correlation or other means.
Examples of Level 2 valuation inputs utilized include over-the-counter broker quotes and quoted prices for similar assets or liabilities that are corroborated by correlation or through statistical relationships between different price curves. For example, certain physical power derivatives are executed for a particular location at specific time periods that might not have active markets; however, an active market might exist for such derivatives for a different time period at the same location. We utilize correlation techniques to compare prices for inputs at both time periods to provide a basis to value the non-active derivative. (See Note 16 to Financial Statements for additional discussion of how broker quotes are utilized.)
Level 3 assets and liabilities consist primarily of more complex long-term power purchases and sales agreements, including longer-term wind and other power purchase and sales contracts and certain natural gas positions (collars) in the long-term hedging program. Level 3 assets and liabilities are valued using significant unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets and liabilities. We use the most meaningful information available from the market, combined with our own internally developed valuation methodologies, to develop our best estimate of fair value. The determination of fair value for Level 3 assets and liabilities requires significant management judgment and estimation.
Valuations of Level 3 assets and liabilities are sensitive to the assumptions used for the significant inputs. Where market data is available, the inputs used for valuation reflect that information as of our valuation date. In periods of extreme volatility, lessened liquidity or in illiquid markets, there may be more variability in market pricing or a lack of market data to use in the valuation process. An illiquid market is one in which little or no observable activity has occurred or one that lacks willing buyers. Valuation risk is mitigated through the performance of stress testing of the significant inputs to understand the impact that varying assumptions may have on the valuation and other review processes performed to ensure appropriate valuation.
As part of our valuation of assets subject to fair value accounting, counterparty credit risk is taken into consideration by measuring the extent of netting arrangements in place with the counterparty along with credit enhancements and the estimated credit rating of the counterparty. Our valuation of liabilities subject to fair value accounting takes into consideration the market’s view of our credit risk along with the existence of netting arrangements in place with the counterparty and credit enhancements posted by us. We consider the credit risk adjustment to be a Level 3 input since judgment is used to assign credit ratings, recovery rate factors and default rate factors.
Level 3 assets totaled $350 million and $283 million at December 31, 2009 and 2008, respectively, and represented approximately 8% and 7%, respectively, of the assets measured at fair value, or less than 1% of total assets. Level 3 liabilities totaled $269 million and $355 million at December 31, 2009 and 2008, respectively, and represented approximately 8% and 7%, respectively, of the liabilities measured at fair value, or less than 1% of total liabilities.
Valuations of several of our Level 3 assets and liabilities are based on long-dated price curves for electricity that are developed internally. Additionally, Level 3 assets and liabilities are sensitive to changes in discount rates, option-pricing model inputs such as volatility factors and credit risk adjustments. As of December 31, 2009, a $5.00 per MWh change in electricity price assumptions across unobservable inputs, primarily related to the outer years in our long-dated pricing model (years that are not market observable) would cause an approximate $72 million change in net Level 3 assets. A 10% change in diesel fuel price assumptions across unobservable inputs would cause an approximate $11 million change in net Level 3 assets. In addition, we have derivative contracts that are valued based on option-pricing models with unobservable inputs. A 10% increase in volatility and correlation related to these contracts would cause an approximate $5 million change in net Level 3 assets. See Note 16 to Financial Statements for additional information about fair value measurements, including a table presenting the changes in Level 3 assets and liabilities for the twelve months ended December 31, 2009.
Revenue Recognition
Our revenue includes an estimate for unbilled revenue that represents estimated daily kWh consumption after the meter read date to the end of the period multiplied by the applicable billing rates. Estimated daily kWh usage is derived using historical kWh usage information adjusted for weather and other measurable factors affecting consumption. Calculations of unbilled revenues during certain interim periods are generally subject to more estimation variability because of seasonal changes in demand. Accrued unbilled revenues totaled $546 million, $505 million and $477 million at December 31, 2009, 2008 and 2007, respectively.
Accounting for Contingencies
Our financial results may be affected by judgments and estimates related to loss contingencies. A significant contingency that we account for is the loss associated with uncollectible trade accounts receivable. The determination of such bad debt expense is based on factors such as historical write-off experience, aging of accounts receivable balances, changes in operating practices, regulatory rulings, general economic conditions, effects of hurricanes and other natural disasters and customers' behaviors. Changes in customer count and mix due to competitive activity and seasonal variations in amounts billed add to the complexity of the estimation process. Historical results alone are not always indicative of future results, causing management to consider potential changes in customer behavior and make judgments about the collectability of accounts receivable. Bad debt expense totaled $113 million, $81 million, $13 million and $46 million for the years ended December 31, 2009 and 2008, the period from October 11, 2007 to December 31, 2007 and the period from January 1, 2007 to October 10, 2007, respectively. The increase in bad debt in 2009 reflected higher delinquencies due to delays in final bills and disconnects resulting from a customer billing and information management system conversion, customer losses and general economic conditions. Amounts in 2008 reflected competitive customer acquisitions in south Texas and the effects of Hurricane Ike. See Note 10 to Financial Statements regarding a reserve recorded in 2008 for amounts due from subsidiaries of Lehman.
Litigation contingencies also may require significant judgment in estimating amounts to accrue. We accrue liabilities for litigation contingencies when such liabilities are considered probable of occurring and the amount is reasonably estimable. No significant amounts have been accrued for such contingencies during the three-year period ended December 31, 2009. See Item 3, “Legal Proceedings” for discussion of major litigation.
Accounting for Income Taxes
Our income tax expense and related balance sheet amounts involve significant management estimates and judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities. Our income tax returns are regularly subject to examination by applicable tax authorities. In management’s opinion, the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future taxes that may be owed as a result of any examination.
As discussed in Note 8 to Financial Statements, in January 2007 we adopted new accounting standards that provide interpretive guidance for accounting for uncertain tax positions. See Notes 1 and 9 to Financial Statements for discussion of income tax matters.
Depreciation and Amortization
Depreciation expense related to generation facilities is based on the estimates of fair value and economic useful lives as determined in the application of purchase accounting described above. The accuracy of these estimates directly affects the amount of depreciation expense. If future events indicate that the estimated lives are no longer appropriate, depreciation expense will be recalculated prospectively from the date of such determination based on the new estimates of useful lives.
The estimated remaining lives range from 23 to 60 years for the lignite/coal- and nuclear-fueled generation units. See Note 1 to Financial Statements under “Property, Plant and Equipment” for discussion of the change from composite to asset-by-asset depreciation effective with the Merger.
As a result of cost-based regulatory rate-setting processes, the book value of the majority of Oncor’s assets and liabilities effectively represent fair value, and no adjustments to those regulated assets or liabilities were recorded as part of purchase accounting for the Merger. Depreciation expense for such assets totaled $394 million, $330 million and $298 million in 2009, 2008 and 2007, or 3.1% of carrying value in 2009 and 2.8% in 2008 and 2007.
Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 3 to Financial Statements for additional information.
Regulatory Assets
The financial statements at December 31, 2009 and 2008, reflect total regulatory assets of $2.170 billion and $2.071 billion, respectively. These amounts include $759 million and $865 million, respectively, of generation-related regulatory assets recoverable by securitization (transition) bonds as discussed immediately below. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. (See “Oncor’s Regulatory Assets and Liabilities” in Note 25 to Financial Statements.)
Generation-related regulatory asset stranded costs arising prior to the 1999 Restructuring Legislation became subject to recovery through issuance of $1.3 billion principal amount of transition bonds in accordance with a regulatory financing order. The carrying value of the regulatory asset upon final issuance of the bonds in 2004 represented the projected future cash flows to be recovered from REPs by Oncor through revenues as a transition charge to service the principal and fixed rate interest on the bonds. The regulatory asset is being amortized to expense in an amount equal to the transition charge revenues being recognized. As discussed in Note 2 to Financial Statements, the regulatory asset and related transition bonds were adjusted to fair value on the date of the Merger in accordance with purchase accounting rules.
Other regulatory assets that we believe are probable of recovery, but are subject to review and possible disallowance, totaled $148 million at December 31, 2009. These amounts consist primarily of storm-related service recovery costs and employee retirement costs.
In August 2009, the PUCT issued a final order in Oncor’s first rate review in more than seven years. As discussed in Note 25 to Financial Statements, the order resulted in a write off of regulatory assets of $25 million.
Defined Benefit Pension Plans and OPEB Plans
We provide pension benefits based on either a traditional defined benefit formula or a cash balance formula and also provide certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from our company. Reported costs of providing noncontributory defined pension benefits and OPEB are dependent upon numerous factors, assumptions and estimates.
PURA provides for the recovery by Oncor of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility. These costs are associated with Oncor's active and retired employees, as well as active and retired personnel engaged in other EFH Corp. activities related to their service prior to the deregulation and disaggregation of our business effective January 1, 2002. Oncor is authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs reflected in Oncor's approved (by the PUCT) billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Accordingly, Oncor defers (principally as a regulatory asset or property) additional pension and OPEB costs consistent with PURA. Amounts deferred are ultimately subject to regulatory approval.
Benefit costs are impacted by actual employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.
In accordance with accounting rules, changes in benefit obligations associated with these factors may not be immediately recognized as costs in the income statement, but are recognized in future years over the remaining average service period of plan participants. As such, significant portions of benefit costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. Pension and OPEB costs as determined under applicable accounting rules are summarized in the following table:
See Note 21 to Financial Statements regarding other disclosures related to pension and OPEB obligations.
Sensitivity of these costs to changes in key assumptions is as follows:
PRESENTATION AND ANALYSIS OF RESULTS
The accompanying statements of consolidated income and cash flows for 2007 are presented for two periods: January 1, 2007 through October 10, 2007 (Predecessor) and October 11, 2007 through December 31, 2007 (Successor), which relate to the period before the Merger and the period after the Merger, respectively. Management's discussion and analysis of results of operations and cash flows has been prepared by comparing the results of operations and cash flows of the Successor for the year ended December 31, 2009 to those of the Successor for the year ended December 31, 2008, by comparing the results of operations and cash flows of the Successor for the three months ended December 31, 2008 to those of the Successor for the period October 11, 2007 through December 31, 2007 and by comparing the results of operations and cash flows of the Successor for the nine months ended September 30, 2008 to those of the Predecessor for the period January 1, 2007 through October 10, 2007. To facilitate the discussion, certain volumetric and statistical data for 2008 have been presented as of and for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007 and as of and for the three months ended December 31, 2008 compared to the three months ended December 31, 2007. Such volumetric and statistical data are measured and reported on a monthly, quarterly and annual basis.
RESULTS OF OPERATIONS
Consolidated Financial Results
Consolidated Financial Results - Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Reference is made to comparisons of results by business segment following the discussion of consolidated results. The business segment comparisons provide additional detail and quantification of items affecting financial results.
Operating revenues decreased $1.818 billion, or 16%, to $9.546 billion in 2009.
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Operating revenues in the Competitive Electric segment decreased $1.876 billion, or 19%, to $7.911 billion.
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Operating revenues in the Regulated Delivery segment increased $110 million, or 4%, to $2.690 billion.
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Net intercompany sales eliminations increased $52 million, reflecting Oncor’s higher distribution revenues from REP subsidiaries of TCEH.
Fuel, purchased power costs and delivery fees decreased $1.717 billion, or 37%, to $2.878 billion in 2009, driven by lower purchased power costs. See discussion below in the analysis of Competitive Electric segment results of operations.
Net gains from commodity hedging and trading activities totaled $1.736 billion in 2009 and $2.184 billion in 2008. Results in 2009 and 2008 included unrealized mark-to-market net gains totaling $1.277 billion and $2.281 billion, respectively, driven by the effect of lower forward market prices of natural gas on the value of positions in the long-term hedging program. See discussion below in the analysis of Competitive Electric segment results of operations.
Operating costs increased $95 million, or 6%, to $1.598 billion in 2009.
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Operating costs in the Competitive Electric segment increased $16 million, or 2%, to $693 million.
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Operating costs in the Regulated Delivery segment increased $80 million, or 10%, to $908 million.
Depreciation and amortization increased $144 million, or 9%, to $1.754 billion in 2009.
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Depreciation and amortization in the Competitive Electric segment increased $80 million, or 7%, to $1.172 billion.
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Depreciation and amortization in the Regulated Delivery segment increased $65 million, or 13%, to $557 million.
SG&A expenses increased $111 million, or 12%, to $1.068 billion in 2009.
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SG&A expenses in the Competitive Electric segment increased $59 million, or 9%, to $741 million.
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SG&A expenses in the Regulated Delivery segment increased $30 million, or 18%, to $194 million.
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Corporate and Other SG&A expenses increased $22 million, or 20%, to $133 million driven by higher transition costs associated with outsourced support services.
See Note 3 to Financial Statements for discussion of the $90 million and $8.860 billion impairments of goodwill in 2009 and 2008, respectively.
Other income totaled $204 million in 2009 and $80 million in 2008, including $39 million and $44 million, respectively, in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. The 2009 amount also included an $87 million debt extinguishment gain (see discussion of debt exchanges in Note 12 to Financial Statements), $23 million of income arising from the reversal of a use tax accrual recorded in purchase accounting related to periods prior to the Merger, which was triggered by a state ruling in the third quarter of 2009, and $21 million of income arising from the reversal of exit liabilities recorded in purchase accounting due to sooner than expected transition of outsourcing services (see Notes 2 and 20 to Financial Statements). The 2008 amount also included a $21 million net insurance recovery for damage to certain mining equipment.
Other deductions totaled $97 million in 2009 and $1.301 billion in 2008. The 2009 amount included an impairment charge of $34 million related to land expected to be sold within the next 12 months and a $25 million write off of regulatory assets as discussed in Note 25 to Financial Statements under “Oncor’s Regulatory Assets and Liabilities.” The 2008 amount included impairment charges of $501 million related to NOx and SO2 environmental allowances intangible assets and $481 million related to trade name intangible assets, both discussed in Note 3 to Financial Statements, $229 million in impairment charges related to the natural gas-fueled generation facilities and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. See Note 10 to Financial Statements for details of other income and deductions.
Interest income increased $18 million, or 67%, to $45 million driven by interest on $465 million in collateral under a funding arrangement described in Note 18 to Financial Statements.
Interest expense and related charges decreased $2.023 billion to $2.912 billion in 2009 reflecting a $696 million unrealized mark-to-market net gain related to interest rate swaps in 2009 as compared to a $1.477 billion net loss in 2008, which was partially offset by $118 million in increased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges and a $34 million decrease in capitalized interest. See Note 25 to Financial Statements.
Income tax expense totaled $367 million in 2009 compared to an income tax benefit of $471 million in 2008. The effective rate on income in 2009 was 47.4%, and the effective rate on a loss in 2008 was 4.5%. The increase in the rate reflects the impacts of nondeductible goodwill impairments of $90 million in 2009 and $8.860 billion in 2008, which increased the effective rate by 5.0 percentage points in 2009 and decreased the effective rate by 24.8 percentage points in 2008. The increase also reflects the effect of interest accrued for uncertain tax positions, which increased the rate on income in 2009 and decreased the rate on a loss in 2008.
Reflecting the goodwill and other impairment charges recorded in 2008, after tax-results improved $10.406 billion to $408 million in net income in 2009.
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After-tax results in the Competitive Electric segment improved $9.560 billion to $631 million in net income in 2009.
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After-tax results in the Regulated Delivery segment improved $806 million to $320 million in net income in 2009.
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Corporate and Other net expenses totaled $543 million in 2009 and $583 million in 2008. The amounts in 2009 and 2008 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The after-tax decrease of $40 million reflected the debt extinguishment gain of $57 million and $16 million in interest income related to the collateral discussed above, partially offset by a $20 million goodwill impairment charge and the $14 million increase in SG&A expense as discussed above.
Consolidated Financial Results - Three Months Ended December 31, 2008 Compared to Successor Period From October 11, 2007 Through December 31, 2007
Reference is made to comparisons of results by business segment following the discussion of consolidated results. The business segment comparisons provide additional detail and quantification of items affecting financial results.
Operating revenues increased $370 million, or 19%, to $2.364 billion in 2008.
•
Operating revenues in the Competitive Electric segment increased $308 million, or 18%, to $1.979 billion.
•
Operating revenues in the Regulated Delivery segment increased $80 million, or 15%, to $612 million.
•
Net intercompany sales eliminations increased $18 million, reflecting Oncor’s higher distribution revenues from REP subsidiaries of TCEH.
Fuel, purchased power costs and delivery fees increased $84 million, or 13%, to $728 million in 2008. See discussion below in the analysis of Competitive Electric segment results of operations.
Net gain (loss) from commodity hedging and trading activities totaled $2.432 billion in net gains in 2008 compared to $1.492 billion in net losses in 2007. Results in 2008 included $2.586 billion in unrealized mark-to-market net gains, and results in 2007 included $1.556 billion in unrealized mark-to-market net losses driven by the effect of changes in forward market prices of natural gas on the value of positions in the long-term hedging program. See discussion below in the analysis of Competitive Electric segment results of operations.
Operating costs increased $77 million, or 25%, to $383 million in 2008.
•
Operating costs in the Competitive Electric segment increased $53 million, or 43%, to $177 million.
•
Operating costs in the Regulated Delivery segment increased $26 million, or 14%, to $208 million.
Depreciation and amortization decreased $22 million, or 5%, to $393 million in 2008.
•
Depreciation and amortization in the Competitive Electric segment decreased $50 million, or 16%, to $265 million.
•
Depreciation and amortization in the Regulated Delivery segment increased $26 million, or 27%, to $122 million.
SG&A expenses increased $29 million, or 13%, to $245 million in 2008.
•
SG&A expenses in the Competitive Electric segment increased $29 million, or 19%, to $183 million.
•
SG&A expenses in the Regulated Delivery segment decreased $7 million, or 16%, to $38 million.
•
Corporate and Other SG&A expenses increased $7 million, or 41%, to $24 million due primarily to incentive compensation and benefits expenses.
See Note 3 to Financial Statements for discussion of the $8.860 billion goodwill impairment charge recorded in the fourth quarter of 2008.
Other income totaled $37 million in 2008 and $14 million in 2007, including $11 million and $10 million, respectively, in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. The 2008 amount also included a $21 million net insurance recovery for damage to certain mining equipment. Other deductions totaled $718 million in 2008 and $61 million in 2007. The 2008 amount included impairment charges of $481 million related to trade name intangible assets and $229 million related to the natural gas-fueled generation fleet. The 2007 amount included $51 million of professional fees incurred related to the Merger. See Note 10 to Financial Statements for details of other income and deductions.
Interest expense and related charges increased $1.592 billion to $2.431 billion in 2008. The increase in interest expense and related charges was partially due to $27 million in expense and charges attributable to the ten fewer days in the 2007 period. The increase reflects increased rates, which includes an unrealized mark-to-market net loss on interest rate swaps of $1.512 billion, and higher average borrowings, partially offset by increased capitalized interest.
Income tax benefit totaled $9 million in 2008 compared to $673 million in 2007. The effective rate on a loss in 2008 was 5.5%, excluding the impact of the $8.860 billion goodwill impairment charge (this nondeductible charge distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion), and the effective rate on a loss in 2007 was 33.1%. The decrease in the rate was driven by an increase in interest accrued for uncertain tax positions.
Reflecting the goodwill impairment charge in 2008, after-tax results declined $7.655 billion to a loss of $9.015 billion in 2008.
•
After-tax results in the Competitive Electric segment declined $6.822 billion to a loss of $8.067 billion in 2008.
•
After-tax results in the Regulated Delivery segment declined $858 million to a loss of $795 million in 2008.
•
Corporate and Other net expenses totaled $153 million in 2008 and $178 million in 2007. The amounts in 2008 and 2007 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The decrease of $25 million was driven by financial advisory, legal and other professional fees in 2007 directly related to the Merger.
Consolidated Financial Results - Nine Months Ended September 30, 2008 Compared to Predecessor Period From January 1, 2007 Through October 10, 2007
Reference is made to comparisons of results by business segment following the discussion of consolidated results. The business segment comparisons provide additional detail and quantification of items affecting financial results.
Operating revenues increased $957 million, or 12%, to $9.001 billion in 2008.
•
Operating revenues in the Competitive Electric segment increased $925 million, or 13%, to $7.809 billion.
•
Operating revenues in the Regulated Delivery segment decreased $18 million, or less than 1%, to $1.969 billion.
•
Net intercompany sales eliminations decreased $50 million, reflecting lower sales by Oncor to REP subsidiaries of TCEH.
Fuel, purchased power costs and delivery fees increased $1.486 billion, or 62%, to $3.867 billion in 2008. See discussion below in the analysis of Competitive Electric segment results of operations.
Net gain (loss) from commodity hedging and trading activities totaled $248 million in net losses in 2008 compared to $554 million in net losses in 2007. Results in 2008 included unrealized mark-to-market net losses totaling $305 million driven by the effect of higher forward market prices of natural gas on the value of hedge positions. See discussion below in the analysis of Competitive Electric segment results of operations.
Operating costs increased $13 million, or 1%, to $1.120 billion in 2008.
•
Operating costs in the Competitive Electric segment increased $29 million, or 6%, to $500 million.
•
Operating costs in the Regulated Delivery segment decreased $17 million, or 3%, to $620 million.
Depreciation and amortization increased $583 million, or 92%, to $1.217 billion in 2008.
•
Depreciation and amortization in the Competitive Electric segment increased $574 million to $827 million.
•
Depreciation and amortization in the Regulated Delivery segment increased $4 million, or 1%, to $370 million.
SG&A expenses increased $21 million, or 3%, to $712 million in 2008.
•
SG&A expenses in the Competitive Electric segment increased $10 million, or 2%, to $499 million.
•
SG&A expenses in the Regulated Delivery segment decreased $13 million, or 9%, to $126 million.
•
Corporate and Other SG&A expenses increased $24 million, or 38%, to $87 million due primarily to Sponsor management fees of $26 million.
Other income totaled $43 million in 2008 and $69 million in 2007. The 2008 amount included $33 million in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. The 2007 amount included $36 million of amortization of a deferred gain on sale of a business that was eliminated in purchase accounting. Other deductions totaled $583 million in 2008 and $841 million in 2007. The 2008 amount included impairment charges of $501 million related to NOx and SO2 environmental allowances intangible assets and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. The 2007 amount included net charges of $755 million related to the cancelled development of eight coal-fueled generation units (see Note 4 to Financial Statements). See Note 10 to Financial Statements for details of other income and deductions.
Interest expense and related charges increased $1.834 billion to $2.505 billion in 2008 reflecting $1.397 billion due to higher average borrowings, driven by the Merger-related financings, and $614 million in higher average interest rates, including $54 million of amortization of debt fair value discount resulting from purchase accounting and a $36 million unrealized mark-to-market net gain related to interest rate swaps, partially offset by $150 million in increased capitalized interest. The increase was also net of $27 million in additional interest in the 2007 period attributable to the ten additional days in the period. See Note 25 to Financial Statements.
Income tax benefit totaled $462 million in 2008 compared to income tax expense of $309 million in 2007. The 2007 amount includes a deferred tax benefit of $70 million related to an amendment of the Texas margin tax by the Texas legislature. Excluding the effect of this 2007 item, the effective income tax rates were 32.0% on a loss in 2008 compared to 37.6% on income in 2007. (The deferred tax benefit in 2007 distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion.) The decrease in the effective tax rate is driven by the effect of interest accrued for uncertain tax positions.
After-tax results declined $1.706 billion to a loss of $983 million in 2008.
•
After-tax results in the Competitive Electric segment declined $1.584 billion to a loss of $862 million in 2008.
•
Net income in the Regulated Delivery segment increased $44 million to $309 million in 2008.
•
Corporate and Other net expenses totaled $430 million in 2008 and $288 million in 2007. The amounts in 2008 and 2007 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The increase of $142 million reflected:
•
a $115 million increase in net interest expense, driven by issuance of Merger-related debt;
•
$23 million in lower other income reflecting the absence, due to purchase accounting, of amortization of a gain on the sale of a business;
•
a $38 million deferred tax benefit in 2007 related to the Texas margin tax, and
•
a $15 million increase in SG&A expense as discussed above.
partially offset by:
•
the write-off in 2007 of $25 million in previously deferred costs related to anticipated strategic transactions (including expected financings) that were no longer expected to be completed as a result of the Merger, and
•
$25 million in financial advisory, legal and other professional fees in 2007 related to the Merger.
Competitive Electric Segment
The following tables present financial operating results of the Competitive Electric segment for the Successor periods of the years ended December 31, 2009 and 2008, the three months ended December 31, 2008, the period from October 11, 2007 through December 31, 2007 and the nine months ended September 30, 2008, and for the Predecessor period from January 1, 2007 through October 10, 2007. Volumetric and other statistical data have been presented as of and for the Successor periods of the years ended December 31, 2009 and 2008, the three months ended December 31, 2008 and 2007 and the nine months ended December 31, 2008, and for the Predecessor period for the nine months ended September 30, 2007.
Financial Results
Competitive Electric Segment
Sales Volume and Customer Count Data
(a) Customers with demand of less than 1 MW annually.
(b) Calculated using average number of customers for the period.
(c) Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department of Commerce). Normal is defined as the average over a 20-year period.
(d) Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number of meters does not reflect the number of individual customers. Each of the year ended December 31, 2008 and three months ended December 31, 2008 and 2007 amounts reflects reclassification of 18 thousand meters, and the nine months ended September 30, 2007 amounts reflect the reclassification of 19 thousand meters from residential to small business to conform to current presentation.
Competitive Electric Segment
Revenue and Commodity Hedging and Trading Activities
(a) Customers with demand of less than 1 MW annually.
(b) Upon settlement of physical derivative power sales and purchase contracts that are marked-to-market in net income, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, instead of the contract price. As a result, these line item amounts include a noncash component, which the company considers “unrealized.” These amounts are as follows:
(c) Represents amortization of the intangible net asset value of retail and wholesale power sales agreements resulting from purchase accounting.
Competitive Electric Segment
Production, Purchased Power and Delivery Cost Data
(a) See note (b) on previous page.
(b) Represents amortization of the intangible net asset values of emission credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel resulting from purchase accounting.
(c) Includes delivery fee charges from Oncor that are eliminated in consolidation.
(d) Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs.
(e) Includes physical purchases and sales, the financial results of which are reported in commodity hedging and trading activities in the income statement.
Competitive Electric Segment - Financial Results - Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Operating revenues decreased $1.876 billion, or 19%, to $7.911 billion in 2009.
Wholesale electricity revenues decreased $1.866 billion, or 56%, to $1.463 billion in 2009 as compared to 2008 when wholesale revenues increased 55%. Volatility in wholesale revenues and purchased power costs reflects movements in natural gas prices, as lower natural gas prices in 2009 drove a 46% decline in average wholesale electricity sales prices. Reported wholesale revenues and purchased power costs also reflect changes in volumes of bilateral contracting activity entered into to mitigate the effects of demand volatility and congestion. Results in 2009 reflect lower demand volatility and a decline in congestion, which drove an 8% decline in wholesale sales volumes.
Bilateral electricity contracting activity includes hedging transactions that utilize contracts for physical delivery. Wholesale sales and purchases of electricity are reported gross in the income statement if the transactions are scheduled for physical delivery with ERCOT.
Comparisons of wholesale balancing activity, reported net, are generally not meaningful because the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, which are highly variable. The activity in 2009 reflected reduced volatility and congestion, in part due to actions taken by ERCOT.
Retail electricity revenues declined $97 million, or 2%, to $6.231 billion and reflected the following:
•
Lower average pricing contributed $242 million to the revenue decline. The change in average pricing reflected lower average contracted business rates driven by lower wholesale electricity prices, partially offset by higher average pricing in the residential and non-contract business markets resulting from advanced meter surcharges as well as customer mix.
•
Retail sales volume growth of 2% increased revenues by $145 million. Volumes rose in the business markets driven by changes in customer mix resulting from contracting activity, but declined slightly in the residential market driven by a 3% decrease in customers.
Other operating revenues decreased $88 million, or 23%, to $292 million in 2009 due to lower natural gas prices and lower volumes on sales of natural gas to industrial customers.
The change in operating revenues also reflected a $41 million decrease in amortization of intangible assets arising from purchase accounting reflecting expiration of retail sales contracts.
Fuel, purchased power costs and delivery fees decreased $1.666 billion, or 30%, to $3.934 billion in 2009. This decrease was driven by lower purchased power costs due to the effect of lower natural gas prices, decreased demand volatility and reduced congestion as discussed above regarding wholesale revenues. Lower costs of replacement power during unplanned generation unit repair outages contributed to improved margin. Other factors contributing to lower fuel and purchased power costs included lower natural gas-fueled generation and lower related fuel costs ($374 million), the effect of lower natural gas prices on natural gas purchased for sale to industrial customers ($116 million) and lower amortization of intangible assets arising from purchase accounting ($26 million).
Overall baseload generation production increased 3% in 2009 reflecting a 5% increase in nuclear production and a 2% increase in lignite/coal-fueled production. The increase in nuclear production, which reflects two refueling outages in 2008 compared to one refueling outage in 2009 and investments to increase generation capacity, resulted in improved margin. The increase in lignite/coal-fueled production reflected generation from the new units placed in service in the fourth quarter 2009, partially offset by generation reductions during certain periods when power could be purchased in the wholesale market at prices below production costs, which was largely due to lower natural gas prices and higher wind generation availability.
Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities for the years ended December 31, 2009 and 2008, which totaled $1.736 billion and $2.184 billion in net gains, respectively:
Year Ended December 31, 2009 - Unrealized mark-to-market net gains totaling $1.277 billion included:
•
$1.260 billion in net gains related to hedge positions, which includes $1.719 billion in net gains from changes in fair value, driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $459 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and
•
$17 million in net gains related to trading positions, which includes $22 million in net gains from changes in fair value and $5 million in net losses that represent reversals of previously recorded net gains on positions settled in the period.
Realized net gains totaling $459 million included:
•
$449 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and
•
$10 million in net gains related to trading positions.
Year Ended December 31, 2008 - Unrealized mark-to-market net gains totaling $2.281 billion included:
•
$2.324 billion in net gains related to hedge positions, which includes $2.282 billion in net gains from changes in fair value and $42 million in net gains that represent reversals of previously recorded fair values of positions settled in the period;
•
$68 million in “day one” net losses related to large hedge positions (see Note 18 to Financial Statements), and
•
$25 million in net gains related to trading positions, which includes $76 million in net gains from changes in fair value and $51 million in net losses that represent reversals of previously recorded fair values of positions settled in the period.
Realized net losses totaling $97 million included:
•
$177 million in net losses related to hedge positions that primarily offset hedged electricity revenues and fuel and purchased power costs recognized in the period, and
•
$80 million in net gains related to trading positions.
Unrealized gains and losses that are related to physically settled derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $52 million in net losses in 2009 and $48 million in net gains in 2008.
Operating costs increased $16 million, or 2%, to $693 million in 2009 driven by $28 million in costs related to the new lignite-fueled generation facilities. The change also reflected $19 million in higher maintenance costs incurred during planned and unplanned lignite-fueled generation unit outages in 2009 that was more than offset by the $31 million effect of two planned nuclear generation unit outages in 2008 as compared to one in 2009.
Depreciation and amortization increased $80 million, or 7%, to $1.172 billion in 2009. The increase was driven by $39 million in higher amortization expense related to the intangible asset representing retail customer relationships recorded in purchase accounting and $24 million due to the placement in service of two new generation units and related mining assets. Increased lignite generation unit depreciation as a result of normal capital additions as well as adjustments to useful lives of components was partially offset by lower natural gas generation unit depreciation resulting from an impairment in 2008.
SG&A expenses increased $59 million, or 9%, to $741 million in 2009. The increase reflected $36 million in higher retail bad debt expense, reflecting higher delinquencies due to delays in final bills and disconnects resulting from a system conversion, customer losses and general economic conditions. The increase also reflected higher employee related expenses, the implementation of a new retail customer information management system and the transition of certain previously outsourced customer operations, partially offset by $13 million in lower fees associated with the sale of receivables program.
See Note 3 to Financial Statements for discussion of the impairments of goodwill of $70 million in 2009 and $8.0 billion in 2008.
Other income totaled $59 million in 2009 and $34 million in 2008. The 2009 amount included a $23 million reversal of a use tax accrual, an $11 million reversal of exit liabilities recorded in connection with the termination of outsourcing arrangements (see Notes 2 and 20 to Financial Statements), a $6 million fee received related to an interest rate swap/commodity hedge derivative agreement, $5 million in royalty income and $5 million in sales/use tax refunds. The 2008 amount included an insurance recovery of $21 million and $4 million in royalty income. See Note 10 to Financial Statements for more details.
Other deductions totaled $68 million in 2009 and $1.274 billion in 2008. The 2009 amount included $34 million in charges for the impairment of land expected to be sold within the next 12 months, $7 million in charges for severance and other individually immaterial miscellaneous expenses. The 2008 amount included $501 million in impairment charges related to NOx and SO2 environmental allowances intangible assets and $481 million related to trade name intangible assets, both discussed in Note 3 to Financial Statements, $229 million in impairment charges related to the natural gas-fueled generation facilities discussed in Note 5 to Financial Statements and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. See Note 10 to Financial Statements for more details.
Interest expense and related charges decreased $2.064 billion, or 51%, to $1.946 billion in 2009. The decrease reflected a $696 million unrealized mark-to-market net gain related to interest rate swaps in 2009 compared to a $1.477 billion net loss in 2008, partially offset by $118 million in increased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges in August 2008.
Income tax expense totaled $407 million in 2009 compared to an income tax benefit totaling $450 million in 2008. Excluding the impacts of the goodwill impairment of $70 million in 2009 and $8.0 billion in 2008, the effective income tax rate was 36.7% in 2009 and 32.6% in 2008. (These nondeductible charges distort the comparison; therefore, they have been excluded for purposes of a more meaningful discussion.) The increase in the rate reflects the effect of interest accrued for uncertain tax positions, which increased the rate on income in 2009 and decreased the rate on a loss in 2008.
After-tax results for the segment improved $9.560 billion to net income of $631 million in 2009, reflecting the 2008 impairment of goodwill, the 2008 impairment charges reported in other deductions and the change in unrealized mark-to-market values of interest rate swaps reported in interest expense, partially offset by lower net gains from commodity hedging and trading activities driven by lower unrealized mark-to-market net gains.
Competitive Electric Segment - Financial Results - Three Months Ended December 31, 2008 Compared to Successor Period from October 11, 2007 through December 31, 2007
Operating revenues increased $308 million, or 18%, to $1.979 billion in 2008.
Retail electricity revenues increased $225 million, or 20%, to $1.367 billion in 2008 and reflected the following:
•
The increase in retail electricity revenues was largely due to $186 million in revenues attributable to the ten fewer days in the 2007 period.
•
Higher average pricing in all markets contributed to the revenue increase, with residential rates increasing an average of 7%, and higher average rates in the business markets reflecting a change in customer mix in the large business market.
•
The effect of higher retail pricing was partially offset by the effect of a 6% decline in total retail sales volumes driven by the business markets. The lower sales volumes in the business markets reflected a decline in commercial and industrial activity due to economic conditions.
•
Total retail electricity customer counts at December 31, 2008 increased 2% from December 31, 2007, driven by a 3% increase in residential customers.
Wholesale electricity revenues increased $27 million, or 5%, to $532 million in 2008. The increase in wholesale electricity revenues reflected $66 million in revenues attributable to the ten fewer days in the 2007 period. The change also reflected lower wholesale electricity prices driven by lower natural gas prices.
The change in operating revenues also reflected a $29 million decrease in amortization of intangible assets arising in purchase accounting.
Fuel, purchased power costs and delivery fees increased $102 million, or 12%, to $954 million in 2008. The increase was largely due to $123 million in costs attributable to the ten fewer days in the 2007 period.
Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities for the three months ended December 31, 2008 and the Successor period from October 11, 2007 through December 31, 2007:
Three Months Ended December 31, 2008 - Net gain totaling $2.432 billion included:
•
Unrealized mark-to-market net gains of $2.586 billion, substantially all of which related to commodity hedge positions and
•
Realized net losses totaling $154 million, including $101 million in net losses related to commodity hedge positions that primarily offset hedged electricity revenues recognized in the period and $53 million in net losses related to trading positions.
Period from October 11 through December 31, 2007 - Net losses totaling $1.492 billion included:
•
Unrealized mark-to-market net losses of $1.556 billion, substantially all of which related to commodity hedge positions and
•
Realized net gains totaling $64 million consisting primarily of net gains related to commodity hedge positions that offset hedged electricity revenues and fuel and purchased power costs recognized in the period.
Operating costs increased $53 million, or 43%, to $177 million in 2008. The increase was partially due to $19 million in costs attributable to the ten fewer days in the 2007 period. The increase in operating costs also reflects higher maintenance costs related to the timing and scope of planned and unplanned outages in baseload generation facilities, higher staffing and benefits costs and expenses associated with operational readiness of the generation units under construction.
Depreciation and amortization decreased $50 million, or 16%, to $265 million in 2008. The decrease in depreciation and amortization reflected lower amortization expense related to the intangible value of customer relationships, partially offset by incremental depreciation expense from stepped-up property, plant and equipment values, both related to purchase accounting and $8 million in expense attributable to the ten fewer days in the 2007 period.
SG&A expenses increased $29 million, or 19%, to $183 million in 2008. The increase was partially due to $15 million in expenses attributable to the ten fewer days in the 2007 period. The increase in SG&A expenses also reflected higher bad debt expense due in part to the effects of Hurricane Ike and higher salaries and contractor costs to support customer growth initiatives and computer system enhancements, net of a decrease in fees associated with the sale of accounts receivable program and lower advertising-related costs.
See Note 3 to Financial Statements for discussion of the $8.0 billion goodwill impairment charge recorded in the fourth quarter of 2008.
Other income totaled $26 million in 2008 and $2 million in 2007. Other income in 2008 included a $21 million insurance recovery for damages to certain mining equipment. Other deductions totaled $715 million in 2008 and $8 million in 2007. Other deductions in 2008 included a charge of $481 million for the impairment of a trade name intangible asset (see Note 3 to Financial Statements) and a $229 million charge to write down the natural gas-fueled generation facilities to fair value (see Note 5 to Financial Statements).
Interest income increased $5 million to $15 million in 2008 reflecting higher average balances of notes/advances to parent.
Interest expense and related charges increased $1.578 billion to $2.187 billion in 2008. The increase was driven by an unrealized mark-to-market net loss on interest rate swaps of $1.512 billion.
Income tax expense on a pre-tax loss for 2008 totaled $2 million compared to a $656 million income tax benefit on a pre-tax loss in 2007. Excluding the impact of the $8.0 billion goodwill impairment in 2008, the effective rate on a pre-tax loss was 3.1% in 2008 compared to 34.5% in 2007. (This nondeductible charge distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion.) The decrease in the rate is driven by the unfavorable impact of tax provision adjustments recorded in 2008 on a small pre-tax loss.
After-tax results for the segment declined by $6.822 billion to a loss of $8.067 billion driven by impairment charges related to goodwill, the trade name intangible asset and the natural gas-fueled generation facilities and the unrealized mark-to-market net losses on interest rate swaps, partially offset by the change in unrealized mark-to-market values of commodity hedge positions in the long-term hedging program.
Competitive Electric Segment - Financial Results - Nine Months Ended September 30, 2008 Compared to Predecessor Period from January 1, 2007 through October 10, 2007
Operating revenues increased $925 million, or 13%, to $7.809 billion in 2008.
Wholesale electricity revenues increased $1.160 billion, or 71%. A 40% increase in average wholesale electricity prices driven by higher natural gas prices contributed $797 million to revenue growth and a 27% increase in sales volumes contributed $429 million. The rise in natural gas prices reflected the overall trend of higher energy prices and increased demand in natural gas-fueled generation due to warmer weather in 2008. Higher wholesale sales and purchase volumes reflected several factors, including increased demand (due to warmer weather), baseload plant outages and congestion, as well as increased near-term bilateral power contracting activity due in part to increased demand and market volatility in 2008. The higher natural gas prices also contributed to the increase in fuel and purchased power costs. The increase in wholesale electricity revenues and sales volumes was partially offset by $66 million in revenues attributable to the ten additional days in the 2007 period.
The $53 million, or 1%, decrease in retail electricity revenues reflected the following:
•
The ten additional days in the 2007 period contributed $186 million to the decrease in retail electricity revenues.
•
The decrease in retail electricity revenues was partially offset by a 2% increase in retail sales volumes that increased revenues by $107 million. Residential volumes increased 4% reflecting the effects of warmer than normal weather in 2008 combined with the cooler than normal weather experienced in 2007 and a 4% increase in residential customer counts. Business and other customer volumes were comparable with 2007.
•
The decrease in retail electricity revenues was also partially offset by higher average pricing that increased revenues by $26 million. Higher average retail pricing reflected higher prices in the business markets driven by higher natural gas prices, partially offset by an approximate $108 million effect of lower pricing in the residential customer market. Lower residential pricing reflected the effect of a 6% price discount in March 2007, an additional 4% price discount in June 2007 and another 5% price discount in October 2007 to those residential customers in Oncor’s service territory with month-to-month service plans and a rate equivalent to the former price-to-beat.
Comparisons of wholesale balancing activity, reported net, are generally not meaningful because the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, which are highly variable. The relatively large amount in 2008 reflects weather-driven volatility, generation facility outages and congestion effects.
Other operating revenues increased $46 million, or 19%, to $293 million primarily due to higher retail natural gas revenues reflecting increased prices, the effect of which was partially offset by $11 million in revenues attributable to the ten additional days in the 2007 period.
Fuel, purchased power costs and delivery fees increased $1.437 billion, or 45%, to $4.646 billion. The increase was driven by higher purchased power costs, reflecting 28% growth in purchased power volumes as well as the effect of higher natural gas prices on wholesale power prices. The increase also reflected greater utilization of natural gas-fueled generation facilities to meet peak demand and a 56% increase in fuel costs per MWh in those facilities due to higher natural gas prices. Higher fuel costs also reflected higher usage and prices (including transportation costs) of purchased coal. The increase reflects $246 million of net expense recorded in the 2008 period representing amortization of the intangible net asset values of environmental credits, coal purchase contracts and power purchase agreements and the stepped-up value of nuclear fuel resulting from purchase accounting. Other cost increases included $101 million related primarily to congestion-related charges and $41 million in higher costs of natural gas for resale. The increase in fuel, purchased power costs and delivery fees was partially offset by $123 million in costs attributable to the ten additional days in the 2007 period.
Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities for the nine months ended September 30, 2008 and the Predecessor period from January 1, 2007 through October 10, 2007, which totaled $248 million and $554 million in net losses, respectively:
Nine Months Ended September 30, 2008 - Unrealized mark-to-market net losses totaling $305 million include:
•
$250 million in net losses related to hedge positions, which includes $248 million in net losses from changes in fair value and $2 million in net losses that represent reversals of previously recorded fair values of positions settled in the period;
•
$69 million in “day one” net losses related to large hedge positions (see Note 18 to Financial Statements), and
•
$13 million in net gains related to trading positions, which includes $79 million in net gains from changes in fair value and $66 million in net losses that represent reversals of previously recorded fair values of positions settled in the period.
Realized net gains totaling $57 million include:
•
$76 million in net losses related to hedge positions that primarily offset hedged electricity revenues recognized in the period, and
•
$133 million in net gains related to trading positions.
Period from January 1, 2007 through October 10, 2007 - Unrealized mark-to-market net losses totaling $722 million include:
•
$566 million in net losses related to hedge positions, which includes $528 million in net losses from changes in fair value and $38 million in net losses that represent reversals of previously recorded fair values of positions settled in the period;
•
$90 million in hedge ineffectiveness net gains, which includes $111 million of net gains from changes in fair values and $21 million in net losses that represent reversals of previously recorded ineffectiveness net gains related to positions settled in the period. These amounts relate to positions accounted for as cash flow hedges;
•
$45 million in net losses related to trading positions, which includes $28 million in net losses from changes in fair values and $17 million in net losses that represent reversals of previously recorded fair values of positions settled in the period;
•
$231 million in “day one” losses related to large hedge positions entered into at below-market prices, and
•
a $30 million “day one” gain related to a power purchase agreement.
Realized net gains totaling $168 million include:
•
$125 million in net gains related to hedge positions that offset hedged electricity revenues and fuel and purchased power costs recognized in the period, and
•
$43 million in net gains related to trading positions.
Operating costs increased $29 million, or 6%, to $500 million in 2008. The increase reflects $36 million in higher maintenance costs related to the timing and scope of planned and unplanned outages in baseload generation facilities, $11 million in costs related to combustion turbines now being operated for our own benefit, $10 million in higher property taxes and $5 million of expenses associated with operational readiness of the generation units under construction, partially offset by $7 million in costs in 2007 for utilization of SO2 credits for the lignite/coal-fueled generation plants and $3 million in individually insignificant items. The increase in operating costs was partially offset by $19 million in costs attributable to the ten additional days in the 2007 period.
Depreciation and amortization increased $574 million to $827 million. The increase includes $502 million of incremental depreciation expense from stepped-up property, plant and equipment values and $38 million in incremental amortization expense related to the intangible value of customer relationships, both resulting from the effects of purchase accounting. The remaining increase primarily reflects normal additions and replacements of equipment in generation operations. The increase in depreciation and amortization was partially offset by $8 million in costs attributable to the ten additional days in the 2007 period.
SG&A expenses increased $10 million, or 2%, to $499 million in 2008. The increase reflects:
•
$26 million in higher expenses in the retail operations, primarily increased employees and labor costs to support customer growth initiatives and increased marketing and computer systems enhancement costs, net of a $6 million decrease in fees associated with the sale of accounts receivable program, and
•
$16 million in higher retail customer bad debt expense,
partially offset by
•
$15 million in expenses attributable to the ten additional days in the 2007 period, and
•
lower administrative costs related to generation facility development activities reflecting the 2007 cancellation of certain coal-fueled generation projects.
Other income totaled $8 million in 2008 and $22 million in 2007. The 2007 amount includes $7 million of royalty income and $6 million in penalties received due to nonperformance under a coal transportation agreement. Other income totaling $3 million in 2007 was attributable to the ten additional days in the period.
Other deductions totaled $559 million in 2008 and $735 million in 2007. The 2008 amount includes $501 million in impairment charges related to NOx and SO2 environmental allowances intangible assets discussed in Note 3 to Financial Statements and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which has filed for protection under Chapter 11 of the US Bankruptcy Code. The 2007 amount includes net charges of $812 million in connection with the cancellation of the development of eight coal-fueled generation units, a $48 million reduction in the liability previously recorded for leases related to gas-fueled combustion turbines that we had ceased operating for our own benefit and a $10 million charge related to the termination of a railcar operating lease. See Note 10 to Financial Statements for more details.
Interest income decreased $225 million, or 83%, to $46 million in 2008 reflecting lower average balances of notes/advances to parent. The ten additional days in the 2007 period contributed $11 million to the decrease.
Interest expense and related charges increased $1.467 billion to $1.824 billion in 2008. The increase reflects $1.672 billion due to higher average borrowings, driven by the Merger-related financings, partially offset by $150 million in increased capitalized interest, a $36 million unrealized mark-to-market gain related to interest rate swaps and $11 million of amortization of debt fair value discount resulting from purchase accounting. The increase was also net of $15 million in additional interest in the 2007 period attributable to the ten additional days in the period.
Income tax benefit on a pretax loss totaled $452 million in 2008 and income tax expense on pretax income totaled $306 million in 2007. The 2007 amount includes a deferred tax benefit of $32 million related to an amendment of the Texas margin tax by the Texas legislature. Excluding the effect of this 2007 item, the effective income tax rates were 34.4% on a loss in 2008 compared to 32.9% on income in 2007. (The deferred tax benefit in 2007 distorts the comparison; therefore it has been excluded for purposes of a more meaningful discussion.) The increase in the effective tax rate is due to a lower lignite depletion benefit in 2008, partially offset by the effect of the Texas margin tax under which interest expense is not deductible.
Net income (loss) decreased $1.584 billion to a net loss of $862 million in 2008 driven by higher net interest expense, the impairment of environmental allowances intangible assets and the effects of purchase accounting, partially offset by the effect of the 2007 impairment charge in connection with the cancellation of certain generation facility development activities and the decrease in net unrealized mark-to-market losses on positions in the long-term hedging program.
Regulated Delivery Segment
The following tables present financial operating results of the Regulated Delivery segment for the Successor periods of the years ended December 31, 2009 and 2008, the three months ended December 31, 2008, the period from October 11, 2007 through December 31, 2007 and the nine months ended September 30, 2008, and for the Predecessor period from January 1, 2007 through October 10, 2007. Volumetric and other statistical data have been presented as of and for the Successor periods of the years ended December 31, 2009 and 2008, the three months ended December 31, 2008 and 2007 and the nine months ended December 31, 2008, and for the Predecessor period for the nine months ended September 30, 2007.
Financial Results
(a) Effective with the sale of noncontrolling interests (see Note 15 to Financial Statements), Oncor is taxed as a partnership and thus not subject to income taxes; however, subsequent to the sale, Oncor reflects a “provision in lieu of income taxes,” and the results of segments are evaluated as if they file their own income tax returns.
Operating Data
(a) SAIDI is the average number of minutes electric service is interrupted per consumer in a year. SAIFI is the average number of electric service interruptions per consumer in a year. CAIDI is the average duration in minutes per electric service interruption in a year. The statistics presented are based on the preceding twelve months’ data.
(b) Includes transition charge revenue associated with the issuance of securitization bonds totaling $147 million and $140 million for the years ended December 31, 2009 and 2008, respectively; $32 million for the three months ended December 31, 2008; $29 million for the period October 11, 2007 through December 31, 2007; $108 million for the nine months ended September 30, 2008 and $116 million for the period January 1, 2007 through October 10, 2007. Also includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs.
Regulated Delivery Segment - Financial Results - Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Operating revenues increased $110 million, or 4%, to $2.690 billion in 2009. The increase reflected:
•
$55 million from increased distribution tariffs, including the August 2009 rate review order;
•
$28 million from a surcharge to recover advanced metering deployment costs and $11 million from a surcharge to recover additional energy efficiency costs, both of which became effective with the January 2009 billing cycle;
•
$20 million in higher transmission revenues reflecting rate increases to recover ongoing investment in the transmission system;
•
an estimated $14 million impact from growth in points of delivery;
•
$9 million performance bonus for meeting PUCT energy efficiency targets, and
•
$7 million in higher charges to REPs related to transition bonds (with an offsetting increase in amortization of the related regulatory asset),
partially offset by an estimated $27 million in lower average consumption primarily due to the effects of milder weather and general economic conditions and $7 million due to less requested REP discretionary and third-party maintenance services.
Operating costs increased $80 million, or 10%, to $908 million in 2009. The increase reflected $45 million in higher fees paid to other transmission entities, $21 million in additional expense recognition as a result of the PUCT’s August 2009 final order in the rate review (see discussion immediately below) and $10 million in costs related to programs designed to improve customer electricity demand efficiency, the majority of which are reflected in the revenue increases discussed above.
Under accounting rules for rate regulated utilities, certain costs are deferred as regulatory assets (see Note 25 to Financial Statements) when incurred and are recognized as expense when recovery of the costs are allowed in revenue under regulatory approvals. Accordingly, beginning in September 2009, the effective date of the new tariffs resulting from the rate review (see “Regulation and Rates” below), Oncor began to amortize as operating costs or SG&A expenses certain costs previously deferred as regulatory assets over the recoverability period under the rate review order and recognized higher costs related to the current period. The additional expense recognized included $14 million related to storm recovery costs and $10 million related to pension and OPEB costs (including $3 million reported in SG&A expense).
Depreciation and amortization increased $65 million, or 13%, to $557 million in 2009. The increase reflected $34 million in higher depreciation due to ongoing investments in property, plant and equipment (including $11 million related to advanced meters), $24 million due to increased depreciation and amortization rates implemented upon the PUCT approval of new tariffs in September 2009 and $7 million in higher amortization of regulatory assets associated with securitization bonds (with an offsetting increase in revenues).
SG&A expenses increased $30 million, or 18%, to $194 million in 2009. The increase reflected $12 million related to advanced meters and $3 million in additional expense recognition as a result of the PUCT’s final order in the rate review, both of which have related revenue increases, $8 million in higher professional and contractor fees driven by outsourcing transition and CREZ development activities and $6 million in higher costs related to employee benefit plans, partially offset by a $3 million one-time reversal of bad debt expense due to the PUCT’s finalization of the Certification of Retail Electric Providers rule in April 2009. Write-offs of uncollectible amounts owed by nonaffiliated REPs are deferred as a regulatory asset (see “Regulation and Rates”).
Taxes other than amounts related to income taxes decreased $5 million, or 2%, to $250 million in 2009 reflecting a decrease in local franchise fees due to decreased volumes of electricity delivered.
See Note 3 to Financial Statements for a discussion of the $860 million goodwill impairment charge recorded in 2008.
Other income totaled $49 million in 2009 and $45 million in 2008. The 2009 and 2008 amounts included accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting totaling $39 million and $44 million, respectively. The 2009 amount also included $10 million due to the reversal of exit liabilities recorded in purchase accounting related to the termination of outsourcing arrangements. See Note 2 to Financial Statements.
Other deductions totaled $34 million in 2009 and $19 million in 2008. The 2009 amount included a $25 million write off of regulatory assets (see Note 25 to Financial Statements). The 2009 and 2008 amounts included costs totaling $2 million and $13 million, respectively, associated with the 2006 rate settlement with certain cities.
Interest income decreased $2 million, or 4%, to $43 million in 2009. The decrease reflected $4 million in lower reimbursement of transition bond interest from TCEH due to lower remaining principal amounts of the bonds and $2 million in lower interest income on temporary cash investments and restricted cash due to lower interest rates, partially offset by $4 million in higher earnings on investments held for certain employee benefit plans.
Interest expense and related charges increased $29 million, or 9%, to $346 million in 2009. The increase reflected $17 million in higher average borrowings, reflecting ongoing capital investments. The increase also reflected $12 million due to higher average interest rates, which was driven by refinancing of short-term borrowings with $1.5 billion of senior secured notes issued in September 2008. The majority of the proceeds of the September 2008 notes issuance was used to pay outstanding short-term borrowings under Oncor’s credit facility.
Income tax expense totaled $173 million in 2009 compared to $221 million in 2008. The effective rate decreased to 35.1% in 2009 from 37.2% in 2008, excluding the impact of the $860 million goodwill impairment in 2008. (This nondeductible charge distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion.) The decrease in the rate was driven by the reversal of accrued interest due to the favorable resolution of uncertain tax positions.
Net income for 2009 totaled $320 million and net loss for 2008 totaled $486 million. The change reflects the $860 million goodwill impairment charge recorded in 2008, as well as $53 million in lower results in 2009 driven by the effect of lower average consumption on revenues, the write-off of certain regulatory assets and increased interest expense.
Regulated Delivery Segment - Financial Results - Three Months Ended December 31, 2008 Compared to Successor Period from October 11, 2007 through December 31, 2007
Operating revenues increased $80 million, or 15%, to $612 million in 2008. The increase is largely due to $68 million in revenues attributable to the ten fewer days in the 2007 period. The increase also reflected increased distribution tariffs to recover transmission costs, the impact of growth in points of delivery and higher transmission revenues primarily due to a rate increase to recover ongoing investment in the transmission system, partially offset by lower average consumption due to the effects of milder weather.
Operating costs increased $26 million, or 14%, to $208 million in 2008. The increase is largely due to $21 million in costs attributable to the ten fewer days in the 2007 period. The increase also reflected higher property taxes and higher fees paid to other transmission entities, partially offset by lower vegetation management expenses.
Depreciation and amortization increased $26 million, or 27%, to $122 million in 2008. The increase included $12 million in costs attributable to the ten fewer days in the 2007 period. The remaining increase largely reflected higher depreciation due to ongoing investments in property, plant and equipment.
SG&A expenses decreased $7 million, or 16%, to $38 million in 2008. The decrease reflected lower incentive compensation expense and decreased employee benefit costs, partially offset by $2 million in costs attributable to the ten fewer days in the 2007 period.
Franchise and revenue-based taxes increased $7 million, or 11%, to $69 million in 2008. The increase is largely due to the ten fewer days in the 2007 period.
See Note 3 to Financial Statements for a discussion of the $860 million goodwill impairment charge recorded in 2008.
Other income totaled $11 million in both 2008 and 2007. The amounts reflected accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting. Other deductions totaled $2 million and $7 million in 2008 and 2007, respectively. The 2007 amount included costs associated with the 2006 rate settlement with certain cities totaling $6 million.
Interest income decreased $1 million, or 8%, to $11 million in 2008. The decrease reflected lower earnings on investments held for certain employee benefit plans, partially offset by $2 million in interest income attributable to the ten fewer days in the 2007 period.
Interest expense and related charges increased by $19 million, or 27%, to $89 million in 2008. The increase included $9 million in costs attributable to the ten fewer days in the 2007 period. The remaining increase reflected $7 million from higher average borrowings, reflecting ongoing capital investments, and $1 million from higher average interest rates.
Income tax expense totaled $41 million in 2008 compared to $30 million in 2007. The effective income tax rate increased to 38.7% in 2008, excluding the impact of the $860 million goodwill impairment charge, from 32.3% in 2007. (This nondeductible charge distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion.) The increase in the effective rate was driven by the impact of higher Texas margin tax due in part to the effects of the tax sharing agreement in 2007 and higher accrued interest related to uncertain tax positions.
Net loss for 2008 totaled $795 million and net income for 2007 totaled $63 million. The change was driven by the $860 million goodwill impairment charge recorded in 2008.
Regulated Delivery Segment - Financial Results - Nine Months Ended September 30, 2008 Compared to Predecessor Period from January 1, 2007 through October 10, 2007
Operating revenues decreased $18 million, or less than 1%, to $1.969 billion in 2008. The decreased revenue reflected:
•
$68 million attributable to the ten additional days in the 2007 period;
•
$19 million in lower revenues due to the absence in 2008 of revenues for installation of third party equipment related to Oncor’s technology initiatives, and
•
$4 million in lower charges to REPs related to securitization bonds (with an offsetting decrease in amortization of the related regulatory asset),
partially offset by:
•
$32 million from increased distribution tariffs to recover higher transmission costs;
•
an estimated $16 million impact from growth in points of delivery;
•
$15 million in higher transmission revenues primarily due to rate increases to recover ongoing investment in the transmission system;
•
an estimated $3 million from higher average consumption, as the estimated effect of warmer weather was partially offset by usage declines, and
•
$7 million in increased miscellaneous revenues, including $3 million of revenues for services provided to REPs and other customers (with a related increase in operating costs) and $2 million of pole contact revenues.
Operating costs decreased $17 million, or 3%, to $620 million in 2008. The decrease reflected:
•
$21 million attributable to the ten additional days in the 2007 period, and
•
$18 million of lower expenses due to the absence in 2008 of costs for installation of third party equipment related to Oncor’s technology initiatives,
partially offset by:
•
$15 million in increased labor and benefits costs for restoration of service as a result of weather events, more stringent service requirements, increased services provided to REPs and other customers and equipment installation activities;
•
$3 million in higher vegetation management expenses, and
•
$3 million in software license and service expenses related to Oncor’s purchase of a broadband over power line (BPL) based “Smart Grid” network in May 2008.
Depreciation and amortization increased $4 million, or 1%, to $370 million in 2008. The increase reflected $21 million in higher depreciation due to ongoing investments in property, plant and equipment, partially offset by $4 million in lower amortization of the regulatory assets associated with securitization bonds (with an offsetting decrease in revenues) and $12 million attributable to the ten additional days in the 2007 period.
SG&A expenses decreased $13 million, or 9%, to $126 million in 2008. The decrease reflected:
•
$7 million in lower incentive compensation expense;
•
$5 million in lower fees due to Oncor’s exit from the sale of accounts receivable program;
•
$4 million in expenses in 2007 related to the rebranding of TXU Electric Delivery Company to Oncor Electric Delivery Company;
•
$2 million attributable to the ten additional days in the 2007 period, and
•
$1 million in decreased bad debt expense,
partially offset by $4 million in higher professional fees and $4 million in increased employee benefits costs.
Franchise and revenue-based taxes decreased $12 million, or 6%, to $186 million in 2008. Of the decrease, $8 million was attributable to the ten additional days in the 2007 period. A decrease in state franchise taxes of $9 million due to the 2007 enactment of the Texas margin tax, which is accounted for as an income tax, was partially offset by a $5 million increase in local franchise fees reflecting increased volumes of electricity delivered. Local franchise fees resulting from the 2006 cities rate settlement totaled $7 million for the nine months ended September 30, 2008 and $5 million for the period from January 1, 2007 through October 10, 2007.
Other income totaled $34 million in 2008 and $3 million in 2007. The 2008 amount reflected accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting.
Other deductions totaled $17 million in 2008 and $27 million in 2007. The 2008 amount includes:
•
$13 million in costs as a result of the 2006 settlement with certain cities related to rates, and
•
$3 million in equity losses (representing amortization expense) related to the ownership interest in an EFH Corp. subsidiary holding computer software.
The 2007 amount includes:
•
$20 million in costs a result of the 2006 cities rate settlement;
•
$3 million in costs related to a cancelled joint venture arrangement, and
•
$2 million in equity losses (representing amortization expense) related to the ownership interest in an EFH Corp. subsidiary.
Interest income decreased $10 million, or 23%, to $34 million in 2008. The decrease reflected $4 million in lower earnings on assets held for certain employee benefit plans, a $3 million decrease in reimbursement of transition bond interest from TCEH and $2 million attributable to the ten additional days in the 2007 period.
Interest expense decreased $13 million, or 5%, to $229 million in 2008. The decrease reflected $9 million attributable to the ten additional days in the 2007 period.
Income tax expense totaled $180 million in 2008 compared to $160 million in 2007. The effective income tax rate decreased to 36.8% in 2008 from 37.6% in 2007. The decrease in the effective rate was primarily driven by a decrease in the benefit from the Medicare subsidy for post-employment benefits.
Net income increased $44 million, or 17%, to $309 million driven by increased revenues and higher other income, which reflects the effects of purchase accounting.
Energy-Related Commodity Contracts and Mark-to-Market Activities
The table below summarizes the changes in commodity contract assets and liabilities for the periods presented. The net changes in these assets and liabilities, excluding “fair value adjustments”, “other activity” and “reclassification” as described below, represent the pretax effect on earnings of positions in the commodity contract portfolio that are marked-to-market in net income (see Note 18 to Financial Statements). The portfolio consists primarily of economic hedges but also includes trading positions.
(a) Represents reversals of previously recognized unrealized gains and losses upon settlement (offsets realized gains and losses recognized in the settlement period).
(b) Represents unrealized gains and losses recognized, primarily related to positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”). Includes gains and losses recorded at contract inception dates (see Note 18 to the Financial Statements).
(c) Represents purchase accounting adjustments arising primarily from the adoption of fair value accounting (largely nonperformance risk effect).
(d) Represents reclassification of fair values of derivatives previously accounted for as cash flow hedges.
(e) These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration, generally related to options purchased/sold and physical natural gas exchange transactions. Activity in 2009 included $36 million for the net payment of option premiums, $29 million in natural gas provided under physical gas exchange transactions and $18 million in amortization of derivative liabilities related to settlement of certain multi-year power sales agreements (see Note 18 to Financial Statements), partially offset by $18 million for expired option premiums. Activity in the 2007 Predecessor period included $257 million (net of amounts settled of $7 million) in liabilities related to certain power sales agreements, net of a $102 million payment related to a structured economic hedge transaction in the long-term hedging program and $64 million in natural gas provided under physical gas exchange transactions.
(f) 2009 amount excludes $4 million in net derivative liabilities related to cash flow hedge positions not marked-to-market in net income.
In addition to the effect on net income of recording unrealized mark-to-market gains and losses that are reflected in the table above, similar effects arise in the recording of unrealized ineffectiveness gains and losses associated with commodity-related positions accounted for as cash flow hedges. These effects on net income, which include reversals of previously recorded unrealized ineffectiveness gains and losses to offset realized gains and losses upon settlement, are reflected in the balance sheet as changes in cash flow hedge and other derivative assets and liabilities (see Note 18 to Financial Statements). The total pretax effect of recording unrealized gains and losses in net income related to commodity contracts is summarized as follows:
Maturity Table - The following table presents the net commodity contract asset arising from recognition of fair values under mark-to-market accounting as of December 31, 2009, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
The “prices actively quoted” category reflects only exchange traded contracts for which active quotes are readily available. The “prices provided by other external sources” category represents forward commodity positions valued using prices for which over-the-counter broker quotes are available in active markets. Over-the-counter quotes for power in ERCOT that are deemed active markets (excluding the West zone) generally extend through 2012 and over-the-counter quotes for natural gas generally extend through 2015, depending upon delivery point. The “prices based on models” category contains the value of all nonexchange traded options, valued using option pricing models. In addition, this category contains other contractual arrangements that may have both forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 16 to Financial Statements for fair value disclosures and discussion of fair value measurements.
COMPREHENSIVE INCOME
Cash flow hedge activity reported in other comprehensive income included (all amounts after-tax):
All amounts included in accumulated other comprehensive income as of October 10, 2007, which totaled $34 million in net gains, were eliminated as part of purchase accounting.
We have historically used, and expect to continue to use, derivative instruments that are effective in offsetting future cash flow variability in interest rates and energy commodity prices. Amounts in accumulated other comprehensive income include the value of dedesignated and terminated cash flow hedges at the time of such dedesignation/termination, less amounts reclassified to earnings as the original hedged transactions are recognized, unless the hedged transactions become probable of not occurring. The effects of the hedge will be recorded in the statement of income as the hedged transactions are actually settled and affect earnings. Also see Note 18 to Financial Statements.
FINANCIAL CONDITION
Liquidity and Capital Resources
Consolidated Cash Flows - Cash flows from operating, financing and investing activities included:
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008 - Cash provided by operating activities totaled $1.711 billion in 2009 compared to $1.505 billion in 2008. The $206 million increase reflected:
•
a $489 million decrease in cash interest paid due to the payment of approximately $465 million of interest with an increase in toggle notes instead of cash as discussed under “Toggle Notes Interest Election” below, and
•
a $57 million favorable impact of timing of advanced metering surcharges,
partially offset by a $347 million decrease in net margin deposits received primarily due to the effects of forward natural gas prices on positions in the long-term hedging program.
Three Months Ended December 31, 2008 Compared to Successor Period from October 11, 2007 through December 31, 2007 - Cash provided by operating activities totaled $548 million in the three months ended December 31, 2008 compared to cash used in operating activities of $450 million in the Successor period from October 11, 2007 through December 31, 2007. The $998 million increase reflects a $1.445 billion favorable change in net margin deposits primarily due to the effect of lower forward natural gas prices on positions in the long-term hedging program and a $143 million favorable change in income taxes paid due to a refund received in 2008, partially offset by a $737 million increase in cash interest payments.
Nine Months Ended September 30, 2008 Compared to Predecessor Period from January 1, 2007 through October 10, 2007 - Cash provided by operating activities totaled $957 million in the nine months ended September 30, 2008 compared to $2.265 billion in the Predecessor period from January 1, 2007 through October 10, 2007. The $1.308 billion decrease reflected a $1.588 billion increase in cash interest payments, partially offset by a $333 million favorable change in margin deposits primarily due to the effect of lower forward natural gas prices on hedge positions.
The decline in capital spending for the year ended December 31, 2009 as compared to the year ended December 31, 2008 primarily reflected a decrease in spending related to the construction of new generation facilities, which is nearing completion, partially offset by capital expenditures in the regulated business for advanced metering deployment and CREZ. Capital expenditures in 2009 totaled $1.324 billion in the Competitive Electric segment and $998 million in the Regulated Delivery segment.
Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $418 million, $460 million, $123 million, $153 million, $337 million and $50 million for the years ended December 31, 2009 and December 31, 2008, the three months ended December 31, 2008, the period from October 11, 2007 through December 31, 2007, the nine months ended September 30, 2008 and the Predecessor period from January 1, 2007 through October 10, 2007, respectively. For the 2007 Predecessor period, this difference represented amortization of nuclear fuel, which is reported as fuel costs in the statement of income consistent with industry practice. For the 2009, 2008 and 2007 Successor periods, this difference also represented amortization of intangible net assets and debt fair value discounts arising from purchase accounting that is reported in various other income statement line items including operating revenues, fuel and purchased power costs, other income and interest expense.
Debt Financing Activity - Activities related to short-term borrowings and long-term debt during the year ended December 31, 2009 are as follows (all amounts presented are principal, and repayments and repurchases, including exchanges, include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):
See Note 12 to Financial Statements for further detail of long-term debt and other financing arrangements.
We, our affiliates or our agents may from time to time purchase our outstanding debt securities for cash in open market purchases or privately negotiated transactions or pursuant to a Section 10b-5(1) plan, or we may refinance existing debt securities. We will evaluate any such transactions in light of market prices of the securities, taking into account liquidity requirements and prospects for future access to capital, contractual restrictions and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material. See Note 12 to Financial Statements for discussion of debt exchange offers completed in November 2009.
Available Liquidity - The following table summarizes changes in available liquidity for the year ended December 31, 2009.
(a) As of December 31, 2009 and 2008, the TCEH Revolving Credit Facility includes $141 million and $144 million, respectively, of commitments from Lehman that are only available from the fronting banks and the swingline lender.
(b) Includes $425 million cash investment (including accrued interest) and $65 million in letters of credit posted related to certain interest rate and commodity hedge transactions. Under the related agreement, the collateral is to be returned no later than March 2010. See Note 18 to Financial Statements.
(c) Pursuant to PUCT rules, TCEH is required to maintain available liquidity to assure adequate credit worthiness of TCEH’s REP subsidiaries, including the ability to return retail customer deposits, if necessary. As a result, at December 31, 2009, the total availability under the TCEH credit facilities should be further reduced by $228 million. See “Regulation and Rates - Certification of REPs.”
Note: Available liquidity above does not include the amounts available from exercising the payment-in-kind (PIK) option on the EFH Corp. Toggle Notes and TCEH Toggle Notes, which for the remaining payment dates from May 2010 through November 2012 could avoid cash interest payments of approximately $1.6 billion.
The $714 million decrease in available liquidity excluding Oncor, after taking into account the short-term investment, was driven by capital spending to construct the new generation facilities.
The decrease in available liquidity for Oncor of $343 million in the year ended December 31, 2009 reflected ongoing capital investment in transmission and distribution infrastructure.
See Note 12 to Financial Statements for additional discussion of these credit facilities.
The net proceeds from the January 2010 issuance of $500 million principal amount of senior secured notes (described in Note 12 to Financial Statements) increased available liquidity.
Pension and OPEB Plan Funding - Pension and OPEB plan funding is expected to total $45 million and $24 million, respectively, in 2010. Based on the funded status of the pension plan at December 31, 2009, funding is expected to total approximately $750 million for the 2010 to 2014 period. Oncor is expected to fund approximately 75% of this amount consistent with its share of the pension liability. We made pension and OPEB contributions of $109 million and $22 million, respectively, in 2009 including transfers of investments related to the salary deferral and supplemental retirement plans totaling $31 million.
See Note 21 to Financial Statements for more information regarding the pension and OPEB plans, including the funded status of the plans as of December 31, 2009.
Toggle Notes Interest Election - EFH Corp. and TCEH have the option every six months at their discretion, ending with the payment due November 2012, to use the payment-in-kind (PIK) feature of their respective toggle notes in lieu of making cash interest payments. We elected to do so for the May 2009, November 2009 and May 2010 interest payments as an efficient and cost-effective method to further enhance liquidity, in light of the weaker economy and related lower electricity demand and the continuing uncertainty in the financial markets. Once EFH Corp. and/or TCEH make a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. and/or TCEH revoke the applicable election. Use of the PIK feature will be evaluated at each election period, taking into account market conditions and other relevant factors at such time.
EFH Corp. made its May and November 2009 interest payments and will make its May 2010 interest payment by using the PIK feature of the its Toggle Notes. During the applicable interest periods, the interest rate on the notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the notes by $150 million and $159 million in May and November 2009, respectively, and will further increase the aggregate principal amount of the notes by $168 million in May 2010. The elections increased liquidity in 2009 by an amount equal to approximately $290 million and will further increase liquidity in May 2010 by an amount equal to approximately $157 million, with such amounts constituting the amount of cash interest that otherwise would have been payable on the notes. If paid in cash, the annual interest expense would increase by approximately $54 million, constituting the additional cash interest that would be payable with respect to the $477 million of additional principal amount. See Note 12 to Financial Statements for discussion of debt exchange offers that resulted in redemption of portions of the outstanding principal of these notes.
Similarly, TCEH made its May and November 2009 interest payments and will make its May 2010 interest payment by using the PIK feature of the its Toggle Notes. During the applicable interest periods, the interest rate on the notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the notes by approximately $98.5 million and $104 million in May and November 2009, respectively, and will further increase the aggregate principal amount of the notes by approximately $110 million in May 2010. The elections increased liquidity in 2009 by an amount equal to approximately $189 million and will further increase liquidity in May 2010 by an amount equal to approximately $103 million, with such amounts constituting the amount of cash interest that otherwise would have been payable on the notes. If paid in cash, the annual interest expense would increase by approximately $33 million, constituting the additional interest that would be payable with respect to the $312 million of additional principal amount.
Liquidity Needs, Including Capital Expenditures - Capital expenditures, including capitalized interest, for 2010 are expected to total approximately $1.950 billion and include:
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$1.0 billion for investment in Oncor’s transmission and distribution infrastructure, including $216 million for Oncor’s investment related to the CREZ Transmission Plan;
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$900 million for investments in TCEH generation facilities, including approximately:
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$700 million for major maintenance, primarily in existing generation operations;
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$150 million related to completion of the construction of a second generation unit and mine development at Oak Grove, and
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$50 million for environmental expenditures related to existing generation units, and
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$50 million for information technology and other corporate investments.
We expect cash flows from operations combined with availability under our credit facilities discussed in Note 12 to Financial Statements to provide sufficient liquidity to fund our current obligations, projected working capital requirements, any restructuring obligations and capital spending for a period that includes the next twelve months.
Liquidity Effects of Commodity Hedging and Trading Activities - Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. TCEH uses cash, letters of credit, asset-backed liens and other forms of credit support to satisfy such collateral obligations. In addition, TCEH’s Commodity Collateral Posting Facility, an uncapped senior secured revolving credit facility, funds the cash collateral posting requirements for a significant portion of the positions in the long-term hedging program not otherwise secured by a first-lien in the assets of TCEH. The aggregate principal amount of this facility is determined by the exposure arising from higher forward market prices, regardless of the amount of such exposure, on a portfolio of certain natural gas hedging transaction volumes. Including those hedging transactions where margin deposits are covered by unlimited borrowings under the TCEH Commodity Collateral Posting Facility, at December 31, 2009, more than 95% of the long-term natural gas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH Senior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral requirements for those hedging transactions. See Note 12 to Financial Statements for more information about this facility.
As of December 31, 2009, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:
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$183 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $317 million posted as of December 31, 2008;
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$516 million in cash has been received from counterparties, net of $4 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $402 million received, net of $122 million in cash posted, as of December 31, 2008;
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$379 million in letters of credit have been posted with counterparties, as compared to $342 million posted as of December 31, 2008, and
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$44 million in letters of credit have been received from counterparties, as compared to $30 million received as of December 31, 2008.
In addition, EFH Corp. (parent) elected to post cash collateral of $400 million in 2009 related to certain TCEH interest rate and commodity hedge transactions (see Note 18 to Financial Statements).
With respect to exchange cleared transactions, these transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variance margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. With respect to cash collateral that is received, such cash collateral is either used for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or it is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties thereby reducing liquidity in the event that it was not restricted. As of December 31, 2009, restricted cash collateral held totaled $1 million. See Note 25 to Financial Statements regarding restricted cash.
With the long-term hedging program, increases in natural gas prices generally result in increased cash collateral and letter of credit postings to counterparties. As of December 31, 2009, approximately 600 million MMBtu of positions related to the long-term hedging program were not directly secured on an asset-lien basis and thus have cash collateral posting requirements. The uncapped TCEH Commodity Collateral Posting Facility supports the collateral posting requirements related to these transactions.
Interest Rate Swap Transactions - See Note 12 to Financial Statements for TCEH interest rate swaps entered into as of December 31, 2009.
Distributions from Oncor - Until December 31, 2012, distributions paid by Oncor to its members are limited to an amount not to exceed Oncor’s net income determined in accordance with GAAP, subject to certain defined adjustments. Distributions are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.
In January 2009, the PUCT awarded approximately $1.3 billion of Competitive Renewable Energy Zone (CREZ) construction projects to Oncor. See discussion below under “Regulation and Rates - Oncor Matters with the PUCT.” As a result of the increased capital expenditures for CREZ and the debt-to-equity ratio cap, we expect that Oncor may retain all or a portion of its available cash to fund such construction instead of paying distributions.
Income Tax Refunds/Payments - Income tax payments, primarily amounts related to the Texas margin tax, are expected to total approximately $75 million in the next 12 months. In 2009, we received a refund totaling $98 million in income taxes and related interest related to IRS audits of 1993 and 1994 income tax returns and made net payments totaling approximately $44 million related to the Texas margin tax. In 2008, we received net federal income tax refunds of $229 million, including $98 million related to 2007 tax payments and $142 million related to a net operating loss carryback to the 2006 tax year. Federal income tax payments totaled $257 million in 2007.
As discussed in Note 8 to Financial Statements, we assess uncertain tax positions under a “more-likely-than-not” standard. We cannot reasonably estimate the ultimate amounts and timing of tax payments associated with uncertain tax positions, but expect that no material federal income tax payments related to such positions will be made in 2010.
Sale of Accounts Receivable - TXU Energy participates in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with transfers and servicing accounting standards. Under the program, TXU Energy (originator) sells retail trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp., which sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions. All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program totaled $383 million and $416 million at December 31, 2009 and 2008, respectively. See Note 1 to Financial Statements for discussion of a new accounting standard that is expected to require consolidation of this program and Note 11 to Financial Statements for a more complete description of the program including the impact of the program on the financial statements for the periods presented and the contingencies that could result in termination of the program and a reduction of liquidity should the underlying financing be settled.
Capitalization - Our capitalization ratios consisted of 104.6% and 106.0% long-term debt, less amounts due currently, and (4.6)% and (6.0)% common stock equity, at December 31, 2009 and 2008, respectively. Total debt to capitalization, including short-term debt, was 104.4% and 105.8% at December 31, 2009 and 2008, respectively.
Financial Covenants, Credit Rating Provisions and Cross Default Provisions - The terms of certain of our financing arrangements contain maintenance covenants with respect to leverage ratios and/or minimum net worth. As of December 31, 2009, we were in compliance with all such maintenance covenants.
Covenants and Restrictions under Financing Arrangements - Each of the TCEH Senior Secured Facilities and the indentures governing substantially all of the debt we have issued in connection with, and subsequent to, the Merger contain covenants that could have a material impact on the liquidity and operations of EFH Corp. and its subsidiaries.
Adjusted EBITDA (as used in the restricted payments covenant contained in the indenture governing the EFH Corp. Senior Notes) for the year ended December 31, 2009 totaled $4.857 billion for EFH Corp. See Exhibit 99(b) and 99(c) for a reconciliation of net income to Adjusted EBITDA for EFH Corp. and TCEH, respectively, for the years ended December 31, 2009 and 2008.
The following table summarizes TCEH’s secured debt to adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and various other financial ratios of EFH Corp., Intermediate Holding and TCEH that are applicable under certain other covenants in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes, the EFH Corp. Senior Notes, the EFH Corp. 9.75% Notes and the EFIH Notes as of December 31, 2009 and 2008 and the corresponding maintenance and other covenant threshold levels as of December 31, 2009:
(a) Threshold level decreases to a maximum of 7.00 to 1.00 effective March 31, 2010 and to a maximum of 6.75 to 1.00 effective December 31, 2010. Calculation excludes debt that ranks junior to the TCEH Senior Secured Facilities.
(b) Although Intermediate Holding currently meets the fixed charge coverage ratio threshold applicable to certain covenants contained in the indenture governing the EFIH Notes, Intermediate Holding’s ability to use such thresholds to incur debt or make restricted payments/investments is currently limited by the covenants contained in the EFH Corp. Senior Notes and the EFH Corp. 9.75% Notes.
(c) The EFH Corp. fixed charge coverage ratio for non-Sponsor Group payments includes the results of Oncor Holdings and its subsidiaries. The EFH Corp. fixed charge coverage ratio for Sponsor Group payments excludes the results of Oncor Holdings and its subsidiaries.
(d) The Intermediate Holding fixed charge coverage ratio for non-EFH Corp. payments includes the results of Oncor Holdings and its subsidiaries. The Intermediate Holding fixed charge coverage ratio for EFH Corp. payments excludes the results of Oncor Holdings and its subsidiaries.
Credit Ratings - The issuer credit ratings as of January 31, 2010 for EFH Corp. and its subsidiaries, except for Oncor, are B-, Caa1 and B by S&P, Moody’s and Fitch, respectively. The issuer credit ratings, as of January 31, 2010, for Oncor are BBB+ and BBB- by S&P and Fitch, respectively.
Additionally, the rating agencies assign credit ratings on certain of our debt securities. The credit ratings assigned for these debt securities as of January 31, 2010 are presented below:
(a) EFH Corp. 9.75% Notes and EFH Corp. 10% Notes.
(b) EFH Corp. 10.875% Notes and EFH Corp. Toggle Notes.
(c) TCEH 10.25% Notes and TCEH Toggle Notes.
(d) All of Oncor’s long-term debt is secured by a first priority lien and is considered senior secured debt.
In November 2009, the credit rating agencies announced certain rating actions shortly after completion of the EFH Corp. debt exchange transaction discussed in Note 12 to Financial Statements. S&P restored its corporate issuer ratings of EFH Corp., EFC Holdings and TCEH with multi-notch upgrades to B- from SD and maintained a negative outlook. Also, S&P established B+ ratings for the new EFH Corp. 9.75% Notes and EFIH Notes, and it completed multi-notch upgrades from ratings of D for issuances subject to the exchange. Previously, in accordance with its “distressed exchange” policy, S&P downgraded the corporate issuer ratings of EFH Corp., EFC Holdings and TCEH to SD from CC and downgraded ratings of issuances subject to the exchange to D from CC. Moody’s affirmed its Caa1 corporate family rating and negative outlook for EFH Corp. and TCEH but upgraded its probability of default rating to Caa2 from Ca as it determined that the final transaction results did not represent a “distressed exchange.” In addition, Moody’s established Caa3 ratings for the new EFH Corp. 9.75% Notes and EFIH Notes and completed upgrades of certain securities due to results of the exchange. Fitch established a rating of B+ on the new EFH Corp. 9.75% Notes and EFIH Notes resulting from the exchange and downgraded its ratings of the EFH Corp. 10.875% and Toggle Notes by one notch to B from B+. Additionally, Fitch affirmed its ratings and outlook for EFH Corp., EFC Holdings and TCEH. The ratings and stable outlook for Oncor were unaffected by the exchange and were affirmed by all three agencies.
In June 2009, Moody’s upgraded the long-term debt rating for Oncor’s senior secured debt by two notches from Baa3 to Baa1 citing, among other things, Oncor’s position as a rate-regulated electric transmission and distribution utility in Texas, reasonably supportive regulatory jurisdiction, solid financial credit metrics, adequate sources of near-term liquidity and the continued evidence of strong corporate independence from EFH Corp. Moody’s ratings outlook for Oncor remains stable.
A rating reflects only the view of a rating agency, and is not a recommendation to buy, sell or hold securities. Ratings can be revised upward or downward at any time by a rating agency if such rating agency decides that circumstances warrant such a change.
Material Credit Rating Covenants and Credit Worthiness Effects on Liquidity - As a result of TCEH’s non-investment grade credit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, as of December 31, 2009, counterparties to those contracts could have required TCEH to post up to an aggregate of $41 million in additional collateral. This amount largely represents the below market terms of these contracts as of December 31, 2009; thus, this amount will vary depending on the value of these contracts on any given day.
Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. As of December 31, 2009, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $29 million, with $15 million of this amount posted for the benefit of Oncor.
The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of December 31, 2009, TCEH maintained availability under its credit facilities of approximately $228 million. See “Regulation and Rates - Certification of REPs.”
The RRC has rules in place to assure adequate credit worthiness of parties that have mining reclamation obligations. Under these rules, should the RRC determine that the credit worthiness of Luminant Generation Company LLC (a subsidiary of TCEH) is not sufficient to support its reclamation obligations, TCEH may be required to post cash or letter of credit collateral support in an amount currently estimated to be approximately $600 million to $800 million. The actual amount (if required) could vary depending upon numerous factors, including Luminant Generation Company LLC’s credit worthiness and the level of mining reclamation obligations.
ERCOT also has rules in place to assure adequate credit worthiness of parties that schedule power on the ERCOT System. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $43 million as of December 31, 2009 (which is subject to weekly adjustments based on settlement activity with ERCOT).
Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As part of this stipulation, TCEH is required to post a letter of credit in an amount equal to $170 million to secure its payment obligations to Oncor if two or more rating agencies downgrade Oncor’s credit ratings below investment grade.
Other arrangements of EFH Corp. and its subsidiaries, including Oncor’s credit facility, the accounts receivable securitization program (see Note 11 to Financial Statements) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the relevant credit ratings.
In the event that any or all of the additional collateral requirements discussed above are triggered, we believe we will have adequate liquidity to satisfy such requirements.
Material Cross Default Provisions - Certain financing arrangements contain provisions that may result in an event of default if there were a failure under other financing arrangements to meet payment terms or to observe other covenants that could or does result in an acceleration of payments due. Such provisions are referred to as “cross default” provisions.
A default by TCEH or any of its restricted subsidiaries in respect of indebtedness, excluding indebtedness relating to the sale of receivables program and hedging obligations, in an aggregate amount in excess of $200 million may result in a cross default under the TCEH Senior Secured Facilities. Under these facilities, such a default will allow the lenders to accelerate the maturity of outstanding balances ($22.357 billion at December 31, 2009) under such facilities.
The indenture governing the TCEH Senior Notes contains a cross acceleration provision where a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of TCEH or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the TCEH Senior Notes.
Under the terms of a TCEH rail car lease, which had approximately $47 million in remaining lease payments as of December 31, 2009 and terminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.
Under the terms of a TCEH rail car lease, which had approximately $53 million in remaining lease payments as of December 31, 2009 and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.
The indentures governing the EFH Corp. Senior Notes, 9.75% and 10% Notes contain a cross acceleration provision whereby a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of EFH Corp. or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the EFH Corp. Senior Notes, 9.75% and 10% Notes.
The indenture governing the EFIH Notes contains a cross acceleration provision whereby a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of Intermediate Holding or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the EFIH Notes.
The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that applies in the aggregate to the originator, any parent guarantor of an originator or any subsidiary acting as collection agent under the program. TXU Receivables Company and EFH Corporate Services Company (a direct subsidiary of EFH Corp.), as collection agent, in the aggregate have a cross default threshold of $50,000. If any of the aforementioned defaults on indebtedness of the applicable threshold were to occur, the program could terminate.
We enter into energy-related and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which vary, stated in the contracts. The subsidiaries whose default would trigger cross default vary depending on the contract.
Each of TCEH’s natural gas hedging agreements that are secured with a lien on its assets on a pari passu basis with the TCEH Senior Secured Facilities contains a cross default provision. In the event of a default by TCEH or any of its subsidiaries relating to indebtedness (such amounts varying by contract but ranging from $200 million to $250 million) that results in the acceleration of such debt, then each counterparty under these hedging agreements would have the right to terminate its hedge agreement with TCEH and require all outstanding obligations under such agreement to be settled.
In the event of a default by TCEH relating to indebtedness in an amount equal to or greater than $200 million that results in the acceleration of such debt, then each counterparty under TCEH’s interest rate swap agreements with an aggregate derivative liability of $1.21 billion at December 31, 2009 would have the right to terminate its interest rate swap agreement with TCEH and require all outstanding obligations under such agreement to be settled.
A default by Oncor or any subsidiary thereof in respect of indebtedness in a principal amount in excess of $50 million may result in a cross default under its credit facility. Under this facility such a default may cause the maturity of outstanding balances ($616 million at December 31, 2009) under such facility to be accelerated.
Other arrangements, including leases, have cross default provisions, the triggering of which would not be expected to result in a significant effect on liquidity.
Long-Term Contractual Obligations and Commitments - The following table summarizes our contractual cash obligations as of December 31, 2009 (see Note 12 to Financial Statements for additional disclosures regarding these long-term debt and noncancellable purchase obligations).
(a) Excludes capital lease obligations, unamortized discounts and fair value premiums and discounts related to purchase accounting. Also excludes $278 million of additional principal amount of notes to be issued in May 2010 and due in 2016 and 2017, reflecting the election of the PIK feature on toggle notes as discussed above under “Toggle Notes Interest Election.”
(b) Includes net amounts payable under interest rate swaps. Variable interest payments and net amounts payable under interest rate swaps are calculated based on interest rates in effect at December 31, 2009.
(c) Includes short-term noncancellable leases.
(d) Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments. Amounts presented for variable priced contracts assumed the year-end 2009 price remained in effect for all periods except where contractual price adjustment or index-based prices were specified.
The following are not included in the table above:
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contracts between affiliated entities and intercompany debt;
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individual contracts that have an annual cash requirement of less than $1 million (however, multiple contracts with one counterparty that are more than $1 million on an aggregated basis have been included);
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contracts that are cancellable without payment of a substantial cancellation penalty;
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employment contracts with management;
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estimated funding of pension plan totaling $45 million in 2010 and approximately $750 million for the 2010 to 2014 period as discussed above under “Pension and OPEB Plan Funding;”
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liabilities related to uncertain tax positions totaling $1.6 billion discussed in Note 8 to Financial Statements as the ultimate timing of payment is not known, and
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capital expenditures under PUCT orders (advanced meters and CREZ projects).
Guarantees - See Note 13 to Financial Statements for details of guarantees.
OFF-BALANCE SHEET ARRANGEMENTS
See discussion above regarding sales of accounts receivable under “Financial Condition - Liquidity and Capital Resources” and in Note 11 to Financial Statements.
Also see Note 13 to Financial Statements regarding guarantees.
COMMITMENTS AND CONTINGENCIES
See Note 13 to Financial Statements for discussion of commitments and contingencies.
CHANGES IN ACCOUNTING STANDARDS
See Note 1 to Financial Statements for a discussion of changes in accounting standards.
REGULATION AND RATES
Regulatory Investigations and Reviews
See Note 13 to Financial Statements.
Certification of REPs
In April 2009, the PUCT finalized a rule relating to the Certification of Retail Electric Providers. The rule strengthens the certification requirements for REPs in order to better protect customers, transmission and distribution utilities (TDUs), and other REPs from the potential insolvency of REPs. The rule, among other things, increases creditworthiness and financial reporting requirements for REPs and provides additional customer protection requirements and regulatory asset consideration for TDU bad debt expenses. Under the rule, Oncor uncollectible amounts owed by REPs are deferred as a regulatory asset. Recovery of the regulatory asset will be considered in a future rate case. Accordingly, Oncor recognized an approximately $3 million one-time reversal of bad debt expense in the three months ended June 30, 2009 (reported in other income). Due to the commitments made to the PUCT in connection with the Merger, Oncor may not recover bad debt expense, or certain other costs and expenses, from rate payers in the event of a TXU Energy default or bankruptcy. Under the rule, REPs are required to amend their certifications, including the manner in which they meet financial requirements, by May 21, 2010. TXU Energy plans to file its amended certification no later than the first quarter 2010. Under the new financial requirements, which will be effective upon approval of the amended certification, the amount of available liquidity required to be maintained by TCEH would have been reduced from $228 million as of December 31, 2009 to approximately $83 million as a result of no longer having to reserve liquidity for payments related to TDUs.
FERC Infrastructure Protection Standards
In September 2009, the FERC issued an order approving a revised set of mandatory NERC standards for critical infrastructure protection (CIP). These standards are designed to protect the nation’s bulk power system against potential disruptions from cyber security breaches. The mandatory reliability standards require certain users, owners and operators of the bulk power system to establish policies, plans and procedures to safeguard physical and electronic access to control systems, to train personnel on security matters, to report security incidents, and to be prepared to recover from a cyber incident. Both Oncor and Luminant were compliant at December 31, 2009 and are expected to achieve “Auditable Compliance” by year-end 2010 in accordance with the NERC CIP implementation schedule.
Wholesale Market Design - Nodal Market
In August 2003, the PUCT adopted a rule that, when implemented, will alter the wholesale market design in the ERCOT market. The rule requires ERCOT to:
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use a stakeholder process to develop a new wholesale market model;
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operate a voluntary day-ahead energy market;
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directly assign all congestion rents to the resources that caused the congestion;
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use nodal energy prices for resources;
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provide information for energy trading hubs by aggregating nodes;
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use zonal prices for loads, and
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provide congestion revenue rights (but not physical rights).
ERCOT currently has a zonal wholesale market structure consisting of four geographic zones. The proposed location-based congestion-management market is referred to as a “nodal” market because wholesale pricing would differ across the various nodes on the transmission grid. The implementation of a nodal market is being done in conjunction with transmission improvements designed to reduce current congestion. Pursuant to a request from the PUCT, ERCOT announced in November 2008 a preliminary schedule for the implementation of the nodal market by December 2010.
ERCOT imposes a surcharge on all Qualified Scheduling Entities in the ERCOT market (including subsidiaries of TCEH) for the purpose of financing 38% of ERCOT’s expected nodal implementation costs. In November 2008, ERCOT filed a request with the PUCT for approval of an interim increase in the nodal surcharge from $0.169 per MWh to $0.375 per MWh. In September 2009, the PUCT approved an increase in the nodal surcharge to $0.375 per MWh, effective January 1, 2010. At the approved $0.375 per MWh nodal surcharge, the annual surcharge to us will be an estimated $30 million to $35 million, which is reported in fuel, purchased power costs and delivery fees. The implementation of a nodal market is scheduled for December 2010. We cannot predict the ultimate impact of the proposed nodal wholesale market design on our operations or financial results.
Environmental Regulations
See discussion in Note 3 to Financial Statements regarding the invalidation of the EPA’s Clean Air Interstate Rule and the related impairment in 2008 of intangible assets representing NOx and SO2 emission allowances.
Oncor Matters with the PUCT
Stipulation Approved by the PUCT - In April 2008, the PUCT entered an order, which became final in June 2008, approving the terms of a stipulation relating to the filing in 2007 by Oncor and Texas Holdings of a Merger-related Joint Report and Application with the PUCT pursuant to Section 14.101(b) of PURA and PUCT Substantive Rule 25.75. The stipulation required the filing of a rate case by Oncor no later than July 1, 2008 based on a test year ended December 31, 2007. In July 2008, Nucor Steel filed an appeal of the PUCT’s order in the 200th District Court of Travis County, Texas. The parties to the appeal have agreed to a schedule that would result in a hearing in June 2010. Oncor was named a defendant and intends to vigorously defend the appeal. Oncor filed the rate case with the PUCT in June 2008, and the PUCT issued a final order with respect to the rate review in August 2009 as discussed below.
Rate Case - In June 2008, Oncor filed for a rate review with the PUCT and 204 cities. In August 2009, the PUCT issued a final order with respect to the rate review. The final order approves a total annual revenue requirement for Oncor of $2.64 billion, based on Oncor’s 2007 test year cost of service and customer characteristics. New rates were calculated for all customer classes using 2007 test year billing metrics and the approved class cost allocation and rate design. The PUCT staff has estimated that the final order results in an approximate $115 million increase in base rate revenues over Oncor’s 2007 adjusted test year revenues, before recovery of rate case expenses. Prior to implementing the new rates in September 2009, Oncor had already begun recovering $45 million of the $115 million increase as a result of approved transmission cost recovery factor and energy efficiency cost recovery factor filings, such as those discussed below. Also see Note 25 to Financial Statements regarding the PUCT’s review of regulatory assets and liabilities.
Key findings made by the PUCT in the rate review include:
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recognizing and affirming Oncor’s corporate ring-fence from EFH Corp. and its unregulated affiliates by rejecting a proposed consolidated tax savings adjustment arising out of EFH Corp.’s ability to offset Oncor’s taxable income against losses from other investments;
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approving the recovery of all of Oncor’s capital investment in its transmission and distribution system, including investment in certain automated meters that will be replaced pursuant to Oncor’s advanced meter deployment plan;
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denying recovery of $25 million of regulatory assets, which resulted in a $16 million after tax loss being recognized in the three months ended September 30, 2009, and
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setting Oncor’s return on equity at 10.25%.
New rates were implemented upon approval of new tariffs in September 2009. In November 2009, the PUCT issued an Order on Rehearing that established a new rate class but did not change the revenue requirements. In January 2010, the PUCT denied all Second Motions for Rehearing, which made the November 2009 Order on Rehearing final and appealable.
Advanced Meter Rulemaking - In 2005, the Texas Legislature passed legislation that authorized electric utilities to implement a surcharge to recover costs incurred in deploying advanced metering and meter information networks. Benefits of the advanced metering installation include improved safety, on-demand meter reading, enhanced outage identification and restoration and system monitoring of voltages. In 2007, the PUCT issued its advanced metering rule to implement this legislation. This rule outlined the minimum required functionality for an electric utility’s advanced metering systems to qualify for cost recovery under a surcharge. Subsequent to the issuance of the rule, the PUCT opened an implementation proceeding for market participants to fine-tune the rule requirements, address the impacts of advanced metering deployment on retail and wholesale markets in ERCOT, and help ensure that retail customers receive benefits from advanced metering deployment. The implementation proceeding is expected to continue through the end of 2010.
Advanced Metering Deployment Surcharge Filing - In May 2008, Oncor filed with the PUCT a description and request for approval of its proposed advanced metering system deployment plan and its proposed surcharge for the recovery of its estimated future investment for advanced metering deployment. Oncor’s plan provides for the full deployment of over three million advanced meters by the end of 2012 to all residential and most non-residential retail electricity customers in Oncor’s service area. As of December 31, 2009, Oncor has installed approximately 660 thousand advanced digital meters, including 620 thousand in the year ended December 31, 2009. Cumulative capital expenditures for the deployment of the advanced meter system totaled $196 million as of December 31, 2009, including $166 million in the year ended December 31, 2009.
In August 2008, a settlement was reached with the majority of the parties to this surcharge filing. The settlement included the following major provisions, as amended by the final order in the 2008 rate review:
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a surcharge beginning on January 1, 2009 and continuing for 11 years;
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a total revenue requirement over the surcharge period of $1.023 billion;
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estimated capital expenditures for advanced metering facilities of $686 million;
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related operation and maintenance expenses for the surcharge period of $153 million;
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$204 million of operation and maintenance expense savings, and
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an advanced metering cost recovery factor of $2.19 per month per residential retail customer and varying from $2.39 to $5.15 per month for non-residential retail customers.
An order approving the settlement was issued by the PUCT in August 2008 and became final in September 2008. Oncor began billing the advanced metering surcharge in the January 2009 billing month cycle. Oncor may, through subsequent reconciliation proceedings, request recovery of additional costs that are reasonable and necessary. While there is a presumption that costs spent in accordance with a plan approved by the PUCT are reasonable and necessary, recovery of any costs that are found not to have been spent or properly allocated, or not to be reasonable or necessary, must be refunded.
Transmission Rates - In order to recover increases in its transmission costs, including incremental fees paid to other transmission service providers due to an increase in their rates, Oncor is allowed to request an update twice a year to the transmission cost recovery factor (TCRF) component of its retail delivery rate charged to REPs. In January 2010, an application was filed to increase the TCRF, which is expected to be administratively approved and become effective in March 2010. This application is expected to increase annualized revenues by $13 million.
In September 2009, Oncor filed an application for an interim update of its wholesale transmission rate, and the PUCT approved the new rate effective December 2009. Accordingly, annualized revenues are expected to increase by approximately $34 million. Approximately $21 million of this increase is recoverable through transmission rates charged to wholesale customers, and the remaining $13 million is recoverable from REPs through the TCRF component of Oncor’s delivery rates.
Application for 2010 Energy Efficiency Cost Recovery Factor - In May 2009, Oncor filed an application with the PUCT to request approval of an energy efficiency cost recovery factor (EECRF) for 2010. PUCT rules require Oncor to make an annual EECRF filing by May 1 for implementation at the beginning of the next calendar year. The requested 2010 EECRF is $54 million, the same amount established for 2009, and would result in the same $0.92 per month charge for residential customers as proposed in Oncor’s rate case. As allowed by the rule, the 2010 EECRF is designed to recover the costs of the 2010 programs, the under-recovery of 2008 program costs, and a performance bonus based on 2008 results. In its November 2009 order, the PUCT approved the application with minor modifications, resulting in an immediate recognition of $9 million in revenues, representing the performance bonus. The final order resulted in a residential EECRF of $0.89 per month due to the PUCT approval of a different allocation methodology for the performance bonus. Oncor’s new EECRF rider became effective for billings on and after December 30, 2009.
Competitive Renewable Energy Zones (CREZs) - In January 2009, the PUCT awarded approximately $1.3 billion of CREZ construction projects to Oncor. The projects involve the construction of transmission lines to support the transmission of electricity from renewable energy sources, principally wind generation facilities, in west Texas to population centers in the eastern part of the state. A written order reflecting the PUCT’s decision was entered in March 2009, and an order on rehearing was issued by the PUCT in May 2009. The cost estimates for the CREZ construction projects are based upon cost analyses prepared by ERCOT in April 2008. For the year ended December 31, 2009, Oncor’s CREZ-related capital expenditures totaled $114 million. It is expected that the necessary permitting actions and other requirements and all construction activities for Oncor’s CREZ construction projects will be completed by the end of 2013.
In October 2009, the PUCT initiated a proceeding to determine whether there is sufficient financial commitment from generators of renewable energy to grant Certificates of Convenience and Necessity (CCNs) for transmission facilities located in two areas in the panhandle of Texas designated as CREZs. If the PUCT determines that there is not sufficient financial commitment from the generators for either CREZ, the PUCT may take action, including delaying the filing of CREZ CCN applications until such time as the PUCT finds sufficient financial commitment for that CREZ in accordance with the financial commitment provisions of the PUCT’s rules. Three of the CREZ transmission projects awarded to Oncor are located in the two CREZs that are the subject of the proceeding. The estimated cost of these three transmission projects is approximately $380 million. The PUCT held a hearing in this proceeding in January 2010. Oncor expects the PUCT to issue an order concluding this proceeding in the second quarter of 2010.
In July 2009, the City of Garland, Texas filed an Original Petition and Application for Stay and Injunction in the 200th District Court of Travis County, Texas seeking judicial review and a stay of the PUCT’s March 2009 written order selecting transmission service providers (including Oncor) to build CREZ transmission facilities. In January 2010, the district court issued an order reversing the PUCT’s order and remanding it to the PUCT for action consistent with the court’s opinion. The district court order did not contain a stay or injunction and severed the City of Garland’s requests for declaratory and injunctive relief. On February 4, 2010, the PUCT issued an order that severs certain of the CREZ transmission projects awarded to Oncor and others from its consideration of the remand of the written order. On February 12, 2010, the PUCT issued an order suspending the schedule sequencing CREZ projects subsequent to CREZ priority projects. In the original sequencing order, Oncor was scheduled to file CCN applications for its five CREZ subsequent projects between March and May 2010. The PUCT’s order stated that the record evidence regarding the selection of the transmission service providers for the CREZ subsequent projects will be reevaluated without delay. Oncor cannot predict the impact, if any, the reevaluation may have on its CREZ construction projects.
Sunset Review
PURA, the PUCT and the RRC will be subject to “sunset” review by the Texas Legislature in the 2011 legislative session. Sunset review includes, generally, a comprehensive review of the need for and effectiveness of an administrative agency (the PUCT or the RRC), along with an evaluation of the advisability of any changes to the PUCT’s authorizing legislation (PURA). A Sunset staff report is scheduled to be issued in April 2010, and a Sunset public meeting is scheduled for May 2010. We cannot predict the outcome of the Sunset review process.
Summary
We cannot predict future regulatory or legislative actions or any changes in economic and securities market conditions. Such actions or changes could significantly alter our basic financial position, results of operations or cash flows.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk is the risk that we may experience a loss in value as a result of changes in market conditions affecting factors such as commodity prices and interest rates, that may be experienced in the ordinary course of business. Our exposure to market risk is affected by a number of factors, including the size, duration and composition of our energy and financial portfolio, as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to manage interest rate risk related to indebtedness, as well as exchange traded, over-the-counter contracts and other contractual arrangements to manage commodity price risk.
Risk Oversight
TCEH manages the commodity price, counterparty credit and commodity-related operational risk related to the unregulated energy business within limitations established by senior management and in accordance with overall risk management policies. Interest rate risk is managed centrally by the corporate treasury function. Market risks are monitored by risk management groups that operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and include, but are not limited to, Value at Risk (VaR) methodologies. Key risk control activities include, but are not limited to, transaction review and approval (including credit review), operational and market risk measurement, validation of transaction capture, portfolio valuation and reporting, including mark-to-market valuation, VaR and other risk measurement metrics.
We have a corporate risk management organization that is headed by the Chief Financial Officer, who also functions as the Chief Risk Officer. The Chief Risk Officer, through his designees, enforces applicable risk limits, including the respective policies and procedures to ensure compliance with such limits and evaluates the risks inherent in our businesses.
Commodity Price Risk
TCEH is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. The company actively manages its portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. The company, similar to other participants in the market, cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices and spark spreads (differences between the market price of electricity and its cost of production).
In managing energy price risk, TCEH enters into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. The company continuously monitors the valuation of identified risks and adjusts positions based on current market conditions. The company strives to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.
Long-Term Hedging Program - See “Significant Activities and Events” above for a description of the program, including potential effects on reported results.
VaR Methodology - A VaR methodology is used to measure the amount of market risk that exists within the portfolio under a variety of market conditions. The resultant VaR produces an estimate of a portfolio’s potential for loss given a specified confidence level and considers among other things, market movements utilizing standard statistical techniques given historical and projected market prices and volatilities.
A Monte Carlo simulation methodology is used to calculate VaR and is considered by management to be the most effective way to estimate changes in a portfolio’s value based on assumed market conditions for liquid markets. The use of this method requires a number of key assumptions, such as use of (i) an assumed confidence level; (ii) an assumed holding period (i.e., the time necessary for management action, such as to liquidate positions); and (iii) historical estimates of volatility and correlation data.
Trading VaR - This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts entered into for trading purposes based on a 95% confidence level and an assumed holding period of five to 60 days.
VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting - This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principally hedges not accounted for as cash flow hedges and trading positions), based on a 95% confidence level and an assumed holding period of five to 60 days.
Earnings at Risk (EaR) - This measurement estimates the potential reduction of pretax earnings for the periods presented, due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities). Transactions accounted for as cash flow hedges are also included for this measurement. A 95% confidence level and a five to 60 day holding period are assumed in determining EaR.
The decreases in the risk measures (MtM VaR and EaR) above were primarily driven by lower natural gas prices in 2009.
Interest Rate Risk
The table below provides information concerning our financial instruments as of December 31, 2009 and 2008 that are sensitive to changes in interest rates, which include debt obligations and interest rate swaps. We have entered into interest rate swaps under which we have exchanged the difference between fixed-rate and variable-rate interest amounts calculated with reference to specified notional principal amounts at dates that generally coincide with interest payments under our credit facilities. In addition, in connection with entering into certain interest rate basis swaps to further reduce fixed borrowing costs, TCEH has changed the variable interest rate terms of certain debt from three-month LIBOR to one-month LIBOR, as discussed in Note 12 to Financial Statements. The weighted average interest rate presented is based on the rate in effect at the reporting date. Capital leases and the effects of unamortized premiums and discounts and fair value hedges are excluded from the table. See Note 12 to Financial Statements for a discussion of changes in debt obligations.
(a) Reflects the remarketing date and not the maturity date for certain debt that is subject to mandatory tender for remarketing prior to maturity. See Note 12 to Financial Statements for details concerning long-term debt subject to mandatory tender for remarketing.
As of December 31, 2009, the potential reduction of annual pretax earnings due to a one percentage point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $42 million, taking into account the interest rate swaps discussed in Note 12 to Financial Statements.
Credit Risk
Credit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potential counterparty’s financial condition, credit rating and other quantitative and qualitative credit criteria and specify authorized risk mitigation tools including, but not limited to, use of standardized master netting contracts and agreements that allow for netting of positive and negative exposures associated with a single counterparty. We have processes for monitoring and managing credit exposure of our businesses including methodologies to analyze counterparties’ financial strength, measurement of current and potential future exposures and contract language that provides rights for netting and set-off. Credit enhancements such as parental guarantees, letters of credit, surety bonds and margin deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed to assess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering into an agreement with a counterparty that creates exposure. Additionally, we have established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Prospective material adverse changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. This process can result in the subsequent reduction of the credit limit or a request for additional financial assurances.
Credit Exposure - Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions arising from hedging and trading activities totaled $2.616 billion at December 31, 2009. The components of this exposure are discussed in more detail below.
Assets subject to credit risk as of December 31, 2009 include $897 million in accounts receivable from the retail sale of electricity to residential and business customers. Cash deposits held as collateral for these receivables totaled $83 million at December 31, 2009. The risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.
Assets subject to credit risk also include accounts receivable from electricity transmission and distribution services. This exposure, which totaled $245 million at December 31, 2009, consists almost entirely of noninvestment grade trade accounts receivable. Of this amount, $180 million represents trade accounts receivable from REPs. Oncor has a customer with subsidiaries that collectively represent 11% of the total exposure. No other nonaffiliated parties represent 10% or more of the total exposure.
The remaining credit exposure arises from wholesale energy sales and purchases and hedging and trading activities, including interest rate hedging. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. As of December 31, 2009, the exposure to credit risk from these counterparties totaled $1.474 billion taking into account the standardized master netting contracts and agreements described above but before taking into account $177 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $1.297 billion increased approximately $502 million in the year ended December 31, 2009, driven by increased derivative asset/decreased derivative liability values due to the effect of changes in natural gas prices and interest rates on the values of our hedge positions.
Of this $1.297 billion net exposure, 99.7% is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and our internal credit evaluation process. Those customers and counterparties without a S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate a S&P equivalent rating. The company routinely monitors and manages credit exposure to these customers and counterparties on this basis.
The following table presents the distribution of credit exposure as of December 31, 2009 arising from wholesale energy sales and purchases and hedging and trading activities. This credit exposure represents wholesale trade accounts receivable and net asset positions on the balance sheet arising from hedging and trading activities after taking into consideration netting and setoff provisions within each contract and any master netting contracts with counterparties.
In addition to the exposures in the table above, contracts classified as “normal” purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform. Nonperformance could have a material adverse impact on future results of operations, financial condition and cash flows.
Significant (10% or greater) concentration of credit exposure exists with three counterparties, which represented 41%, 37% and 12% of the net $1.297 billion exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the applicable counterparty’s credit rating and the importance of our business relationship with the counterparty. However, this concentration increases the risk that a default would have a material effect on results of operations.
With respect to credit risk related to the long-term hedging program, over 99% of the transaction volumes are with counterparties with an A credit rating or better. However, there is current and potential credit concentration risk related to the limited number of counterparties that comprise the substantial majority of the program with such counterparties being in the banking and financial sector. The transactions with these counterparties contain certain credit rating provisions that would require the counterparties to post collateral in the event of a material downgrade in the credit rating of the counterparties. An event of default by one or more hedge counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to us. While the potential concentration of risk with these counterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through the various ongoing risk management measures described above.
FORWARD-LOOKING STATEMENTS
This report and other presentations made by us contain “forward-looking statements.” All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that we expect or anticipate to occur in the future, including such matters as projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our business and operations (often, but not always, through the use of words or phrases such as “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “should,” “projection,” “target,” “goal,” “objective” and “outlook”), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors under Item 1A, “Risk Factors” and the following important factors, among others, that could cause our actual results to differ materially from those projected in such forward-looking statements:
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prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, FERC, the PUCT, the RRC, the NRC, the EPA and the TCEQ, with respect to, among other things:
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allowed prices;
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allowed rates of return;
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permitted capital structure;
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industry, market and rate structure;
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purchased power and recovery of investments;
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operations of nuclear generating facilities;
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operations of mines;
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acquisitions and disposal of assets and facilities;
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development, construction and operation of facilities;
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decommissioning costs;
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present or prospective wholesale and retail competition;
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changes in tax laws and policies, and
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changes in and compliance with environmental and safety laws and policies, including climate change initiatives;
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legal and administrative proceedings and settlements;
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general industry trends;
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economic conditions, including the current recessionary environment;
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our ability to attract and retain profitable customers;
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our ability to profitably serve our customers;
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restrictions on competitive retail pricing;
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changes in wholesale electricity prices or energy commodity prices;
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changes in prices of transportation of natural gas, coal, crude oil and refined products;
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unanticipated changes in market heat rates in the ERCOT electricity market;
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our ability to effectively hedge against changes in commodity prices, market heat rates and interest rates;
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weather conditions and other natural phenomena, and acts of sabotage, wars or terrorist activities;
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unanticipated population growth or decline, or changes in market demand and demographic patterns;
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changes in business strategy, development plans or vendor relationships;
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access to adequate transmission facilities to meet changing demands;
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unanticipated changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;
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unanticipated changes in operating expenses, liquidity needs and capital expenditures;
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commercial bank market and capital market conditions and the potential impact of disruptions in US credit markets;
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access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability of funds in capital markets;
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financial restrictions placed on us by our credit facilities and indentures governing our debt instruments;
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our ability to generate sufficient cash flow to make interest payments on our debt instruments;
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competition for new energy development and other business opportunities;
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inability of various counterparties to meet their obligations with respect to our financial instruments;
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changes in technology used by and services offered by us;
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changes in electricity transmission that allow additional electricity generation to compete with our generation assets;
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significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur;
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changes in assumptions used to estimate costs of providing employee benefits, including pension and OPEB benefits, and future funding requirements related thereto;
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changes in assumptions used to estimate future executive compensation payments;
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hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards;
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significant changes in critical accounting policies;
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actions by credit rating agencies;
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our ability to effectively execute our operational strategy;
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our ability to implement cost reduction initiatives, and
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with respect to our lignite-fueled generation construction and development program, more specifically, our ability to fund such investments, changes in competitive market rules, adverse judicial rulings, changes in environmental laws or regulations, changes in electric generation and emissions control technologies, changes in projected demand for electricity, changes in wholesale electricity prices or energy commodity prices, transmission capacity and constraints, force majeure events and our ability to manage the significant construction, commissioning and start-up program to a timely conclusion with limited cost overruns.
Any forward-looking statement speaks only as of the date on which it is made, and there is no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
INDUSTRY AND MARKET INFORMATION
The industry and market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by ERCOT or the PUCT. We did not commission any of these publications or reports. Some data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Independent industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies and publications is reliable, we have not independently verified such data and make no representation as to the accuracy of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions regarding general economic growth are used in preparing the forecasts included in this report. Similarly, while we believe that such internal and external research is reliable, it has not been verified by any independent sources, and we make no assurances that the predictions contained therein are accurate.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Energy Future Holdings Corp.
Dallas, Texas
We have audited the accompanying consolidated balance sheets of Energy Future Holdings Corp. and subsidiaries (“EFH Corp.”) as of December 31, 2009 and 2008 (successor), and the related statements of consolidated income (loss), comprehensive income (loss), cash flows and equity for the years ended December 31, 2009 and 2008 (successor), the period from October 11, 2007 through December 31, 2007 (successor) and the period from January 1, 2007 through October 10, 2007 (predecessor). These financial statements are the responsibility of EFH Corp.’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Energy Future Holdings Corp. and subsidiaries as of December 31, 2009 and 2008 (successor), and the results of their operations and their cash flows for the years ended December 31, 2009 and 2008 (successor), the period from October 11, 2007 through December 31, 2007 (successor) and the period from January 1, 2007 through October 10, 2007 (predecessor), in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, EFH Corp. completed its merger with Texas Energy Future Merger Sub Corp and became a subsidiary of Texas Energy Future Holdings Limited Partnership on October 10, 2007.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), EFH Corp.’s internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 18, 2010 expressed an unqualified opinion on EFH Corp.’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 18, 2010
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME (LOSS)
(Millions of Dollars)
See Notes to Financial Statements.
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
(Millions of Dollars)
See Notes to Financial Statements.
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS (CONT.)
(Millions of Dollars)
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS (CONT.)
(Millions of Dollars)
See Notes to Financial Statements.
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
See Notes to Financial Statements.
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED EQUITY
(Millions of Dollars)
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED EQUITY (CONT.)
(Millions of Dollars)
See Notes to Financial Statements.
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
Description of Business
EFH Corp., a Texas corporation, is a Dallas-based holding company conducting its operations principally through its TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority (approximately 80%) owned subsidiary engaged in regulated electricity transmission and distribution operations in Texas.
On October 10, 2007, EFH Corp. completed its Merger with Merger Sub. As a result of the Merger, EFH Corp. became a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. See Note 2.
References in this report to “we,” “our,” “us” and “the company” are to EFH Corp. and/or its subsidiaries, TCEH and/or its subsidiaries, or Oncor and/or its subsidiary as apparent in the context. See “Glossary” for other defined terms.
Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor. Such measures include, among other things: the sale of a 19.75% equity interest in Oncor to Texas Transmission in November 2008; maintenance of separate books and records for the Oncor Ring-Fenced Entities; Oncor’s board of directors being comprised of a majority of independent directors, and prohibitions on the Oncor Ring-Fenced Entities providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or other obligations of any member of the Texas Holdings Group. Moreover, Oncor’s operations are conducted, and its cash flows managed, independently from the Texas Holdings Group. Oncor Holdings is consolidated with EFH Corp. as a variable interest entity under consolidations accounting standards.
See Note 15 for discussion of noncontrolling interests sold by Oncor in November 2008.
We have two reportable segments: the Competitive Electric segment, which is comprised principally of TCEH, and the Regulated Delivery segment, which is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary. See Note 24 for further information concerning reportable business segments.
Basis of Presentation
The consolidated financial statements have been prepared in accordance with US GAAP. The accompanying consolidated statements of income (loss), comprehensive income (loss), cash flows and equity present results of operations and cash flows for “Successor” and “Predecessor” periods, which relate to periods succeeding and preceding the Merger, respectively. The consolidated financial statements have been prepared on the same basis as the audited financial statements included in the 2008 Form 10-K. The consolidated financial statements of the Successor reflect the application of purchase accounting in accordance with the provisions of accounting standards related to business combinations, include the activities of Merger Sub, all of which related to the acquisition of EFH Corp., and reflect the adoption of accounting standards related to the determination of fair value. Certain reclassifications have been made to conform prior period data to current period presentation. All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated. Subsequent events have been evaluated through February 18, 2010, the date these consolidated financial statements were issued.
Discontinued Businesses
Results from discontinued businesses, which are reported as discontinued operations, during the period October 11, 2007 to December 31, 2007 totaled $1 million in net income and during the period from January 1, 2007 to October 10, 2007 totaled $24 million in net income and consisted primarily of insurance proceeds related to a 2005 TXU Europe litigation settlement agreement.
Use of Estimates
Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments, other than those disclosed elsewhere herein, were made to previous estimates or assumptions during the current year.
Purchase Accounting
The Merger was accounted for under purchase accounting, whereby the total purchase price of the transaction was allocated to our identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values, and the excess of the purchase price over the fair value of net assets acquired was recorded as goodwill. The allocation resulted in a significant amount of goodwill, an increase in the carrying value of property, plant and equipment and deferred income tax liabilities as well as new identifiable intangible assets and liabilities. Reported earnings in periods subsequent to the Merger reflect increases in interest, depreciation and amortization expense. See Note 2 for details regarding the effect of purchase accounting.
Derivative Instruments and Mark-to-Market Accounting
We enter into contracts for the purchase and sale of electricity, natural gas and other commodities and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses, unless the criteria for certain exceptions are met, and an offsetting derivative asset or liability is recorded in the balance sheet. This recognition is referred to as “mark-to-market” accounting. The fair values of our unsettled derivative instruments under mark-to-market accounting are reported in the balance sheet as commodity and other derivative contractual assets or liabilities. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. See Notes 16 and 18 for additional information regarding fair value measurement and commodity and other derivative contractual assets and liabilities. Under the election criteria of accounting standards related to derivative instruments and hedging activities, we may elect the “normal” purchase and sale exemption. A commodity-related derivative contract may be designated as a “normal” purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement.
Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for “hedge accounting,” which provides for the designation of such instruments as cash flow or fair value hedges if certain conditions are met. A cash flow hedge mitigates the risk associated with the variability of the future cash flows related to an asset or liability (e.g., a forecasted sale of electricity in the future at market prices or the payment of interest related to variable rate debt), while a fair value hedge mitigates risk associated with fixed future cash flows (e.g., debt with fixed interest rate payments). In accounting for changes in the fair value of cash flow hedges, derivative assets and liabilities are recorded on the balance sheet with an offset to other comprehensive income or loss to the extent the hedges are effective and the hedged transaction remains probable of occurring. If the hedged transaction becomes probable of not occurring, hedge accounting is discontinued and the amount recorded in other comprehensive income is immediately reclassified into net income. If the relationship between the hedge and the hedged transaction ceases to exist or is dedesignated, hedge accounting is discontinued, and the amounts recorded in other comprehensive income are recognized as the previously hedged transaction impacts earnings. Changes in value of fair value hedges are recorded as derivative assets or liabilities with an offset to net income, and the carrying value of the related asset or liability (hedged item) is adjusted for changes in fair value with an offset to net income. If the fair value hedge is settled prior to the maturity of the hedged item, the cumulative fair value gain or loss associated with the hedge is amortized into income over the remaining life of the hedged item. In the statement of cash flow, the effects of settlements of derivative instruments are classified consistent with the related hedged transactions.
To qualify for hedge accounting, a hedge must be considered highly effective in offsetting changes in fair value of the hedged item. Assessment of the hedge’s effectiveness is tested at least quarterly throughout its term to continue to qualify for hedge accounting. Changes in fair value that represent hedge ineffectiveness, even if the hedge continues to be assessed as effective, are immediately recognized in net income. Ineffectiveness is generally measured as the cumulative excess, if any, of the change in value of the hedging instrument over the change in value of the hedged item. See Notes 12 and 18 for additional information concerning hedging activity.
Realized and unrealized gains and losses from transacting in energy-related derivative instruments are primarily reported in the income statement in net gain (loss) from commodity hedging and trading activities. In accordance with accounting rules, upon settlement of physical derivative sales and purchase contracts that are marked-to-market in net income, related wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, instead of the contract price. As a result, this noncash difference between market and contract prices is included in the operating revenues and fuel and purchased power costs and delivery fees line items of the income statement, with offsetting amounts included in net gain (loss) from commodity hedging and trading activities.
Revenue Recognition
We record revenue from electricity sales and delivery service under the accrual method of accounting. Revenues are recognized when electricity or delivery services are provided to customers on the basis of periodic cycle meter readings and include an estimated accrual for the revenues earned from the meter reading date to the end of the period (unbilled revenue).
Our reported revenues include, on a net basis, ERCOT electricity balancing transactions, which represent wholesale purchases and sales of electricity for real-time balancing purposes as measured in 15-minute intervals. As is industry practice, these purchases and sales with ERCOT, as the balancing energy clearinghouse agent, are reported net in the income statement. Balancing transactions are difficult to predict, with results varying from period to period between net revenues and net expense, and are reported as a component of revenues in the income statement.
Impairment of Long-Lived Assets
We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. See Note 5 for details of the impairment of the natural gas-fueled generation facilities recorded in 2008.
Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 3 to Financial Statements for additional information.
Goodwill and Intangible Assets with Indefinite Lives
We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually. The impairment tests performed are based on discounted cash flow analyses. See Note 3 for details of goodwill and intangible assets with indefinite lives, including discussion of goodwill and trade name intangible assets impairments recorded in 2009 and 2008.
In 2009, we changed the annual test date for goodwill and intangible assets with indefinite lives from October 1 to December 1. Management determined the new annual goodwill test date is preferable because of efficiencies gained by aligning the test with our annual budget and five-year plan processes in the fourth quarter. The change in the annual test date did not delay, accelerate or avoid an impairment charge, and retrospective application of this change in accounting principle did not affect previously reported results.
Amortization of Nuclear Fuel
Amortization of nuclear fuel is calculated on the units-of-production method and is reported as fuel costs.
Major Maintenance
Major maintenance costs incurred during generation plant outages and the costs of other maintenance activities are charged to expense as incurred and reported as operating costs.
Defined Benefit Pension Plans and Other Postretirement Employee Benefit Plans
We offer pension benefits based on either a traditional defined benefit formula or a cash balance formula and also offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from the company. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. The pension and OPEB accrued benefit obligations reported in the balance sheet are in accordance with accounting standards related to employers’ accounting for defined benefit pension and other postretirement plans. See Note 21 for additional information regarding pension and OPEB plans.
Stock-Based Incentive Compensation
Prior to the Merger, we provided discretionary awards payable in EFH Corp. common stock to qualified managerial employees under our shareholder-approved long-term incentive plans. In December 2007, our board of directors established our 2007 Stock Incentive Plan, which authorizes discretionary grants to directors, officers and qualified managerial employees of EFH Corp. or its affiliates of non-qualified stock options, stock appreciation rights, restricted shares, shares of common stock, the opportunity to purchase shares of common stock and other stock-based awards. Stock-based compensation expense is recognized over the vesting period based on the grant-date fair value of those awards. See Note 22 for information regarding stock-based incentive compensation.
Sales and Excise Taxes
Sales and excise taxes are accounted for as a “pass through” item on the balance sheet; i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction.
Franchise and Revenue-Based Taxes
Unlike sales and excise taxes, franchise and gross receipt taxes are not a “pass through” item. These taxes are assessed to us by state and local government bodies, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates charged to customers by us are intended to recover the franchise and gross receipt taxes, but we are not acting as an agent to collect the taxes from customers.
Income Taxes
We file a consolidated federal income tax return, and federal income taxes are calculated for our subsidiaries substantially as if the entities file separate income tax returns. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities. Effective with the sale of noncontrolling interests in Oncor (see Note 15), Oncor became a partnership for US federal income tax purposes, and we provide deferred income taxes on the difference between the book and tax basis of our investment in Oncor. Previously earned investment tax credits were deferred and amortized as a reduction of income tax expense over the estimated lives of the related properties. In connection with purchase accounting, the remaining unamortized investment tax credit amount related to unregulated businesses of $300 million was eliminated. Investment tax credits related to Oncor’s regulated operations will continue to be amortized over the lives of the related properties in accordance with regulatory treatment. Certain provisions of the accounting guidance for income taxes provide that regulated enterprises are permitted to recognize deferred taxes as regulatory tax assets or tax liabilities if it is probable that such amounts will be recovered from, or returned to, customers in future rates.
Accounting for Contingencies
Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 13 for a discussion of contingencies.
Cash and Cash Equivalents
For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered to be cash equivalents.
We held an interest in The Reserve’s US Government Fund, which began liquidation proceedings in September 2008 due to the credit crisis and withdrawal demands. In September 2008, we attempted to redeem our interest, totaling $242 million, in the US Government Fund, but due to the liquidation process, the funds were not immediately made available; accordingly, such amount was reclassified from cash and cash equivalents to investment held in money market fund. We received $100 million of the funds in November 2008 and the remaining $142 million in January 2009.
Restricted Cash
The terms of certain agreements require the restriction of cash for specific purposes. At December 31, 2009, $1.135 billion of cash is restricted to support letters of credit. See Notes 12 and 25 for more details regarding this and other restricted cash.
Property, Plant and Equipment
As a result of purchase accounting, carrying amounts of property, plant and equipment related to unregulated businesses on the Merger date were adjusted to estimated fair values. Subsequent additions are recorded at cost. Regulated properties at Oncor continue to be reported at original cost, which is considered to be fair value due to the cost-based regulated recovery and returns associated with those assets. The cost of self-constructed property additions includes materials and both direct and indirect labor and applicable overhead, including payroll-related costs.
Depreciation of our property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties. As is common in the industry, the Predecessor historically recorded depreciation expense using composite depreciation rates that reflected blended estimates of the lives of major asset groups as compared to depreciation expense calculated on a component asset-by-asset basis. Effective with the Merger, depreciation expense for unregulated properties is calculated on a component asset-by-asset basis. Estimated depreciable lives are based on management’s estimates of the assets’ economic useful lives. See Note 25.
In accordance with the PUCT’s August 2009 order in Oncor’s rate review, the remaining net book value and anticipated removal cost of existing meters that are being replaced by advanced meters is being charged (amortized) to expense over an 11-year cost recovery period.
Capitalized Interest
Interest related to qualifying construction projects and qualifying software projects are capitalized in accordance with accounting guidance related to capitalization of interest cost. See Note 25.
Inventories
All inventories are reported at the lower of cost (on a weighted average basis) or market unless expected to be used in the generation of electricity. Also see discussion immediately below regarding environmental allowances and credits.
Environmental Allowances and Credits
Effective with the Merger, we began accounting for all environmental allowances and credits as identifiable intangible assets with finite lives that are subject to amortization. The recorded values of these intangible assets were originally established reflecting fair value determinations as of the date of the Merger under purchase accounting. Amortization expense associated with these intangible assets is recognized on a unit of production basis as the allowances or credits are consumed in generation operations. The environmental allowances and credits are assessed for impairment when conditions or events occur that could affect the carrying value of the assets. See Note 3 for details of impairment amounts recorded in 2008.
Regulatory Assets and Liabilities
The financial statements of our regulated electricity delivery operations reflect regulatory assets and liabilities under cost-based rate regulation in accordance with accounting standards related to the effect of certain types of regulation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. See Note 25 for details of the regulatory assets and liabilities.
Investments
Investments in a nuclear decommissioning trust fund are carried at fair market value in the balance sheet. Investments in unconsolidated business entities over which we have significant influence but do not maintain effective control, generally representing ownership of at least 20% and not more than 50% of common equity, are accounted for under the equity method. Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at market value. See Note 19 for details of investments.
Noncontrolling Interests
See Note 15 for discussion of accounting for the noncontrolling interests of Oncor.
Changes in Accounting Standards
In January 2010, the FASB issued guidance on disclosure about fair value measurements. The guidance requires new disclosures of transfers in and out of Levels 1 and 2 of the fair value hierarchy and separate disclosure about purchases, sales, issuances and settlements in Level 3 of the fair value hierarchy. The guidance also provides clarification on disclosures related to the level of disaggregation among assets and liabilities and to the inputs and valuation techniques used to measure fair value. This new guidance is effective for periods beginning January 1, 2010, except for the new disclosures about purchases, sales, issuances and settlements in Level 3, which are effective for periods beginning January 1, 2011. As this new guidance provides only disclosure requirements, the adoption will not have any effect on reported results of operations, financial condition or cash flows.
In August 2009, the FASB issued guidance on measuring fair value of liabilities, which provides clarification of fair value measurement when there is limited or no observable data available. The adoption of this guidance, as of October 1, 2009, did not have any effect on reported results of operations, financial condition or cash flows, and did not have any effect on the disclosures of the fair value of our debt provided in Note 17.
In June 2009, the FASB issued “The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles,” which establishes the FASB Accounting Standards Codification™ (Codification) as the source of authoritative US GAAP recognized by the FASB to be applied to nongovernmental entities. The Codification was effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of the Codification did not affect reported results of operations, financial condition or cash flows.
In June 2009, the FASB issued new guidance that requires reconsideration of consolidation conclusions for all variable interest entities and other entities with which we are involved. This new guidance is effective January 1, 2010. The provisions of this guidance could result in different consolidation conclusions than reached under previous guidance, as the emphasis is on the power to direct the activities of the variable interest entity instead of risk and reward. We continue to evaluate the impact of this new guidance on our financial statements. In consideration of the ring-fencing measures in place, as discussed above under “Description of Business,” our evaluation may result in the deconsolidation of Oncor Holdings and its subsidiaries, which are the ring-fenced entities.
In June 2009, the FASB issued new guidance regarding accounting for transfers of financial assets that eliminates the concept of a qualifying special purpose entity, changes the requirements for derecognizing financial assets and requires additional disclosures. This new guidance is effective in the first quarter of 2010. We continue to evaluate the impact of this new guidance on our financial statements and footnote disclosures; however, we expect that our accounts receivable securitization program discussed in Note 11 will no longer be accounted for as a sale of accounts receivable as a result of the guidance, and the funding under the program will be reported as short-term borrowings. We do not expect this new guidance to impact the covenant-related ratio calculations in our debt agreements.
In May 2009, the FASB issued new guidance related to subsequent events that requires disclosure of the date through which we have evaluated subsequent events related to the financial statements being issued and the basis for that date. Our adoption of this guidance as of April 1, 2009 did not affect reported results of operations, financial condition or cash flows, and the required disclosure is provided above in “Basis of Presentation.”
In April 2009, the FASB issued new guidance regarding determining fair value when the volume and level of activity for the asset or liability have significantly decreased or market transactions are not orderly. We adopted this guidance as of April 1, 2009. While this guidance did not change our fair value measurement techniques, it requires disclosures of additional detail of securities held in our nuclear decommissioning trust that are provided in Notes 16 and 19.
In April 2009, the FASB issued new guidance regarding the recognition and presentation of other-than-temporary impairments, which changed the guidance for recording impairment of investments in debt securities. Our adoption as of April 1, 2009 did not affect the accounting for our nuclear decommissioning trust fund because the trust balance has historically been reported at fair value, with changes in fair value of the trust resulting in changes in Oncor’s regulatory asset or liability related to the decommissioning cost.
In December 2008, the FASB issued new guidance for employers’ disclosures about postretirement benefit plan assets. This new guidance provides enhanced disclosures regarding how investment allocation decisions are made and certain aspects of fair value measurements on plan assets. The required disclosures are intended to provide transparency related to the types of assets and associated risks in an employer’s defined benefit pension or other postretirement employee benefits plan and events in the economy and markets that could have a significant effect on the value of plan assets. As this new guidance provides only disclosure requirements, our adoption as of December 31, 2009 did not have any effect on reported results of operations, financial condition or cash flows. The disclosures are provided in Note 21.
In March 2008, the FASB issued amended disclosure guidance for derivative instruments and hedging activities. This amended guidance enhances required disclosures regarding derivatives and hedging activities to enable investors to better understand their effects on an entity’s financial position, financial performance and cash flows. As this guidance provides only disclosure requirements, our adoption as of January 1, 2009 did not have any effect on reported results of operations or financial condition. The disclosures are provided in Note 18.
2. FINANCIAL STATEMENT EFFECTS OF THE MERGER
As discussed in Note 1, the Merger was completed on October 10, 2007. The aggregate purchase price paid for the equity securities of EFH Corp. was $31.9 billion, which was financed by a combination of equity invested by the Sponsor Group and certain other investors and by borrowings under a senior secured credit facility and senior unsecured interim facilities. These facilities also funded the repayment and redemption of certain existing credit facilities and debt upon completion of the Merger. See Note 12 for a discussion of our debt.
The statements of consolidated income (loss) and cash flows for 2007 present Predecessor results from January 1 through October 10 and Successor results from October 11 through December 31.
Sources and Uses
The sources and uses of the funds for the Merger are summarized in the table below.
(a) Interim facility that was repaid with the proceeds from the issuance of the EFH Corp. Senior Notes that are discussed in Note 12.
(b) Consists of equity contributions by the Sponsor Group and certain other investors.
(c) Represents 461.2 million outstanding shares of EFH Corp. common stock multiplied by $69.25 per share.
(d) Represents professional fees incurred by the Sponsor Group that were directly associated with the Merger and accounted for as part of the purchase price.
Purchase Price Allocation
We accounted for the Merger under purchase accounting in accordance with the provisions of accounting standards related to business combinations, whereby the total purchase price of the transaction was allocated to our identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of the Merger date as summarized in the table below. The fair values were determined based upon assumptions related to future cash flows, discount rates, and asset lives as well as factors more unique to us, our industry and the competitive wholesale power market that include forward natural gas price curves and market heat rates, retail customer attrition rates, generation plant operating and construction costs, and the effect on generation facility values of lignite fuel reserves and mining capabilities using currently available information. As a result of cost-based regulatory rate-setting processes, the book value of the majority of Oncor’s assets and liabilities effectively represent fair value, and no adjustments to those regulated assets or liabilities were recorded. The excess of the purchase price over the fair value of net assets acquired was recorded as goodwill.
The goodwill amount recorded upon finalization of purchase accounting in 2008 totaled $23.2 billion. Management believes the drivers of the goodwill amount include the incremental value of the future cash flow potential of the baseload generation facilities, including facilities under construction, over the values assigned to those assets under purchase accounting rules, considering the market-pricing mechanisms and growth potential in the ERCOT market, as well as the value derived from the scale of the retail business. Management also believes that the goodwill reflects the value of the relatively stable, long-lived cash flows of the regulated business, considering the constructive regulatory environment and market growth potential. See Note 3 for disclosures related to goodwill, including an impairment recorded in the fourth quarter of 2008 and first quarter of 2009.
The following table summarizes the components of the final purchase price allocation:
The following table summarizes the change in the total amount of goodwill during 2008 as a result of purchase accounting:
The above changes relate largely to finalization of fair values of natural gas-fueled generation plants and amounts related to the Capgemini outsourcing agreement, as well as the effects on related deferred income tax balances.
Accrued liabilities were recorded in purchase accounting for exit activities resulting from the Merger. Exit liabilities recorded related to the cancellation of the development of coal-fueled generation facilities discussed in Note 4, the exit of certain administrative activities and the termination of outsourcing arrangements with Capgemini under change of control provisions of such arrangements (see Note 20). The following table summarizes the changes to the exit liability:
(a) Additional amounts recorded upon finalization of purchase accounting.
(b) Represents reversal of exit liabilities due primarily to a shorter than expected outsourcing services transition period.
(c) Remaining accrual is expected to be settled in 2010, the targeted date to complete the transition of outsourced activities back to us or to service providers.
Unaudited Pro Forma Financial Information
The following unaudited pro forma financial position and results of operations assume that the Merger-related transactions occurred on January 1, 2007. The unaudited pro forma information is provided for informational purposes only and is not necessarily indicative of what our results of operations would have been if the Merger-related transactions had occurred on that date, or what our results of operations will be for any future periods.
For the year ended December 31, 2007, unaudited pro forma revenues and net loss were $10.0 billion and $2.3 billion, respectively. Pro forma adjustments for the year ended December 31, 2007 consist of adjustments for the Predecessor period and consist of $473 million in depreciation and amortization expense (including amounts recognized in revenues or fuel and purchased power costs), $2.1 billion in interest expense and a $895 million income tax benefit.
3. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS
Goodwill
As discussed in Note 2, we accounted for the Merger under purchase accounting. The total goodwill amount recorded as a result of purchase accounting totaled $23.2 billion, representing the excess of the purchase price over the fair value of the tangible and identifiable intangible net assets acquired in the Merger; subsequently, impairment charges were recorded in the fourth quarter of 2008 and the first quarter of 2009 (discussed immediately below). Accounting guidance related to goodwill and other intangible assets requires that goodwill be assigned to “reporting units,” which management has determined to be the Competitive Electric segment and the Regulated Delivery segment, which are largely comprised of TCEH and Oncor, respectively. The original goodwill amounts assigned to the Competitive Electric segment of $18.3 billion and the Regulated Delivery segment of $4.9 billion were based on the enterprise values of those businesses at the closing date of the Merger and the completion of purchase accounting.
Reported goodwill as of December 31, 2009 totaled $14.3 billion, with $10.2 billion assigned to the Competitive Electric segment and $4.1 billion to the Regulated Delivery segment. Reported goodwill as of December 31, 2008 totaled $14.4 billion, with $10.3 billion assigned to the Competitive Electric segment and $4.1 billion to the Regulated Delivery segment. None of this goodwill balance is being deducted for tax purposes.
Goodwill and Trade Name Intangible Asset Impairments
The 2009 annual impairment testing performed as of October 1, and December 1, 2009 for goodwill and intangible assets with indefinite useful lives in accordance with accounting guidance for a change in annual impairment testing dates resulted in no impairment (see discussion in Note 1 regarding change in the annual impairment test date from October 1 to December 1). The goodwill testing determined that the estimated fair value (enterprise value) of the Regulated Delivery segment exceeded its carrying value by approximately 10% resulting in no additional testing being required and no impairment for the segment. Key assumptions in the valuation of the regulated business include discount rates, growth of the rate base and return on equity allowed by the regulatory authority. Cash flows of the regulated business are relatively stable and more predictable than the competitive business. The Competitive Electric segment carrying value exceeded its estimated enterprise value (by less than 10%), so the estimated enterprise value of the segment was compared to the estimated fair values of its operating assets and liabilities. This additional testing indicated that the implied goodwill amount exceeded the recorded goodwill amount, and thus no goodwill impairment was recorded. The estimated enterprise value of the Competitive Electric segment reflects the impact of the decline in forward natural gas prices on wholesale electricity prices. Because lower wholesale electricity prices also result in lower fair values of our generation assets, calculated implied goodwill was sufficient to support the recorded goodwill amount. Key variables in the tests included forward natural gas prices, electricity prices, market heat rates and discount rates, assumptions regarding each of which could have a significant effect on valuations. Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.
In the first quarter of 2009, we recorded a $90 million goodwill impairment charge largely related to the Competitive Electric segment. This charge resulted from the completion of fair value calculations supporting the initial $8.860 billion goodwill impairment charge that was recorded in the fourth quarter of 2008 and consisted of an impairment of $8.0 billion related to the Competitive Electric segment and $860 million related to the Regulated Delivery segment. The impairment charge primarily reflected the dislocation in the capital markets during the fourth quarter of 2008 that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies. The impairment determination involved significant assumptions and judgments in estimating enterprise values of the Competitive Electric and Regulated Delivery segments and the fair values of their assets and liabilities. This cumulative $8.950 billion charge is the only goodwill impairment recorded since the Merger.
Also in the fourth quarter of 2008, we recorded a trade name intangible asset impairment charge totaling $481 million ($310 million after-tax). The impairment primarily arises from the increase in the discount rate used in estimating fair value as discussed above.
Although the annual impairment test date for goodwill and intangible assets with indefinite lives set by management was October 1, management determined that in consideration of the continuing deterioration of securities values during the fourth quarter of 2008, an impairment testing trigger occurred subsequent to that test date; consequently, the impairment charges were based on estimated fair values at December 31, 2008. See Note 1 for discussion of the change of the annual impairment test date to December 1 in 2009.
The calculations supporting the impairment determination utilized models that took into consideration multiple inputs, including commodity prices, debt yields, equity prices of comparable companies and other inputs. Those models were generally used in developing long-term forward price curves for certain commodities and discount rates for determining fair values of our reporting units as well as certain individual assets and liabilities of those businesses. The fair value measurements resulting from such models are classified as Level 3 non-recurring fair value measurements consistent with accounting standards related to the determination of fair value (see Note 16).
Identifiable Intangible Assets
Identifiable intangible assets reported in the balance sheet are comprised of the following:
Details of amortization expense related to intangible assets (including income statement line item in which the amortization is included) follows:
Separately identifiable and previously unrecognized intangible assets acquired and recorded as part of purchase accounting for the Merger are described as follows:
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Retail Customer Relationship - Retail customer relationship intangible asset represents the estimated fair value of the non-contracted customer base and is being amortized using an accelerated method based on customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life.
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Favorable Purchase and Sales Contracts - Favorable purchase and sales contracts intangible asset primarily represents the above market value, based on observable prices or estimates, of commodity contracts for which: (i) we have made the “normal” purchase or sale election allowed by accounting standards related to derivative instruments and hedging transactions or (ii) the contracts did not meet the definition of a derivative. The amortization periods of these intangible assets are based on the terms of the contracts. Unfavorable purchase and sales contracts are recorded as other noncurrent liabilities and deferred credits (see Note 25).
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Trade name - The trade name intangible asset represents the estimated fair value of the TXU Energy trade name, and was determined to be an indefinite-lived asset not subject to amortization. This intangible asset will be evaluated for impairment at least annually in accordance with accounting guidance related to goodwill and other intangible assets. See above for discussion of an impairment charge recorded in 2008.
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Environmental Allowances and Credits - This intangible asset represents the fair value, based on observable prices or estimates, of environmental credits, substantially all of which were expected to be used in our power generation activities. These credits are amortized utilizing a units-of-production method.
Impairment of Environmental Allowances and Credits Intangible Assets
In March 2005, the EPA issued regulations called the Clean Air Interstate Rule (CAIR) for 28 states, including Texas, where our generation facilities are located. CAIR requires reductions of SO2 and NOx emissions from power generation facilities in these states. The SO2 reductions were beyond the reductions required under the Clean Air Act’s existing acid rain cap-and-trade program (the Acid Rain Program). CAIR also established a new regional cap-and-trade program for NOx emissions reductions.
In July 2008, the US Court of Appeals for the D.C. Circuit (the D.C. Circuit Court) invalidated CAIR. The D.C. Circuit Court did not overturn the existing cap-and-trade program for SO2 reductions under the Acid Rain Program.
Based on the D.C. Circuit Court’s ruling, we recorded a noncash impairment charge to earnings in 2008. We impaired NOx allowances in the amount of $401 million (before deferred income tax benefit). As a result of the D.C. Circuit Court’s decision, NOx allowances would no longer be needed, and thus there would not be an actively traded market for such allowances. Consequently, our NOx allowances would likely have very little value absent reversal of the D.C. Circuit Court’s decision or promulgation of new rules by the EPA. In addition, we impaired SO2 allowances in the amount of $100 million (before deferred income tax benefit). While the D.C. Circuit Court did not invalidate the Acid Rain Program, we would have more SO2 allowances than we would need to comply with the Acid Rain Program. While there continued to be a market for SO2 allowances, the D.C. Circuit Court’s decision resulted in a material decrease in the market price of SO2 allowances.
The impairment amounts recorded in 2008 were reported in other deductions and reflected in the results of the Competitive Electric segment.
In December 2008, in response to an EPA petition, the D.C. Circuit Court reversed, in part, its previous ruling. Such reversal confirmed CAIR is not valid, but allowed it to remain in place while the EPA revises CAIR to correct the previously identified shortcomings. Since the D.C. Circuit Court did not prescribe a deadline for this revision, at this time, we cannot predict how or when the EPA may revise CAIR.
Estimated Amortization of Intangible Assets - The estimated aggregate amortization expense of intangible assets for each of the next five fiscal years is as follows:
4. CHARGES RELATED TO CANCELLED DEVELOPMENT OF COAL-FUELED GENERATION FACILITIES
In 2007, we recorded a net charge totaling $757 million ($492 million after-tax), substantially all of which was in the Predecessor period, in connection with the February 2007 suspension of the development of eight coal-fueled generation units. This decision and subsequent terminations of equipment orders required an evaluation of the recoverability of recorded assets associated with the development program. The net charge included $705 million for the impairment of construction work-in-process asset balances (primarily pre-construction development costs), $79 million for costs arising from terminations of equipment orders, $29 million for the write-off of deferred financing costs and a $57 million gain on sale (in early October 2007) of two in-process boilers. Additional charges totaling $12 million ($8 million after-tax) were recorded in 2008, which primarily represented costs for transportation and storage of materials.
The construction work-in-process asset balances totaled $871 million prior to the writedown and included progress payments made and accruals for amounts due to equipment suppliers, based on percentage of completion estimates, engineering and design services costs, site preparation expenditures, internal salary and related overhead costs for personnel engaged directly in construction management activities and capitalized interest. The remaining carrying value of assets related to the program at December 31, 2009 totaled $77 million and represented estimated recovery amounts, using a probability-weighted methodology, from equipment salvage and potential resale activities. Cumulative net cash proceeds through December 31, 2009 from the sale of the impaired assets totaled $172 million.
We have terminated all of the equipment orders, with the exception of one purchase order for a boiler that we are attempting to sell, and the air permit applications related to the eight units were formally withdrawn from the TCEQ in October 2007 after the close of the Merger. The net charges arising from cancellation of this development program have been classified in other deductions and are reported in the results of the Competitive Electric segment.
5. IMPAIRMENT OF NATURAL GAS-FUELED GENERATION FACILITIES
In 2008, we performed an evaluation of our natural gas-fueled generation facilities for impairment. The impairment test was triggered by a determination that it was more likely than not that certain generation units would be retired or mothballed (idled) earlier than previously expected. The natural gas-fueled generation units are generally operated to meet peak demands for electricity and all such facilities are tested for impairment as an asset group. As a result of the evaluation, it was determined that an impairment existed, and a charge of $229 million ($147 million after-tax) was recorded to write down the assets to fair value of approximately $28 million, which was determined based on discounted estimated future cash flows. The impairment was reported in other deductions in the Competitive Electric segment.
6. STIPULATION APPROVED BY THE PUCT
Oncor and Texas Holdings agreed to the terms of a stipulation, which was conditional upon completion of the Merger, with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. In February 2008, the PUCT entered an order approving the stipulation. The PUCT issued a final order on rehearing in April 2008 that has been appealed to 200th District Court of Travis County, Texas. The parties to the appeal have agreed to a schedule that would result in a hearing in June 2010.
In addition to commitments Oncor made in its filings in the PUCT review, the stipulation included the following provisions, among others:
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Oncor provided a one-time $72 million refund to its REP customers in the September 2008 billing cycle. The refund was in the form of a credit on distribution fee billings. The liability for the refund was recorded as part of purchase accounting.
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Consistent with the 2006 cities rate settlement (see Note 7), Oncor filed a system-wide rate case in June 2008 based on a test-year ended December 31, 2007. In August 2009, the PUCT issued a final order on this rate case. See Note 25.
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Oncor agreed not to request recovery of approximately $56 million of regulatory assets related to self-insurance reserve costs and 2002 restructuring expenses. These regulatory assets were eliminated as part of purchase accounting.
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The dividends paid by Oncor will be limited through December 31, 2012, to an amount not to exceed Oncor’s net income (determined in accordance with GAAP, subject to certain defined adjustments) for the period beginning October 11, 2007 and ending December 31, 2012, and are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.
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Oncor committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions.
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Oncor committed to an additional $100 million in spending over the five-year period ending December 31, 2012 on demand-side management or other energy efficiency initiatives. These additional expenditures will not be recoverable in rates, and this amount was recorded as a regulatory liability as part of purchase accounting and consistent with accounting standards related to the effect of certain types of regulation.
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If Oncor’s credit rating is below investment grade with two or more rating agencies, TCEH will post a letter of credit in an amount of $170 million to secure TXU Energy’s payment obligations to Oncor.
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Oncor agreed not to request recovery of the $4.9 billion of goodwill resulting from purchase accounting or any future impairment of the goodwill in its rates.
7. CITIES RATE SETTLEMENT IN 2006
In January 2006, Oncor agreed with a steering committee representing 108 cities in Texas (Cities) to defer the filing of a system-wide rate case with the PUCT to no later than July 1, 2008 (based on a test year ending December 31, 2007). Oncor filed the rate case with the PUCT in June 2008, and the PUCT issued a final order on the case in 2009. Oncor extended the benefits of the agreement to 292 nonlitigant cities. The agreements provided that Oncor would make payments to participating cities totaling approximately $70 million, including incremental franchise taxes.
This amount was recognized in earnings over the period from May 2006 through June 2008. Amounts recognized totaled $11 million in 2009, $23 million in 2008, $8 million for the period October 11, 2007 through December 31, 2007 and $25 million for the period January 1, 2007 through October 10, 2007, of which $2 million, $13 million, $6 million and $20 million, respectively, were reported in other deductions (see Note 10), with the remainder reported in franchise and revenue-based taxes. Amounts recognized in 2009 represented extension of benefits per the agreement related to the timing of completion of the rate case.
8. ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES
Effective January 1, 2007, we adopted accounting guidance related to uncertain tax positions. This guidance requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable. We applied updated guidance to determine if each tax position was effectively settled for the purpose of recognizing previously uncertain tax positions. We completed our review and assessment of uncertain tax positions and in the 2007 Predecessor period recorded a net benefit to retained earnings and a decrease to noncurrent liabilities of $33 million in accordance with the new accounting rule.
We file income tax returns in US federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. Examinations of our income tax returns for the years ending prior to January 1, 2003 are complete, but the tax years 1997 to 2002 remain in appeals with the IRS. The conclusion of issues contested from the 1997 to 2002 audit, including matters related to TXU Europe, is not expected to occur prior to 2011. In 2008, we were notified of the commencement of an IRS audit of tax years 2003 to 2006. The audit is expected to require two years to complete. Texas franchise and margin tax returns are under examination or still open for examination for tax years beginning after 2002.
In 2008, we participated in negotiations with the IRS regarding the 2002 worthlessness loss associated with our discontinued Europe business, and we reduced the liability for uncertain tax positions in accordance with accounting guidance. The reduction in the liability of approximately $375 million was largely offset by a reduction of deferred tax assets related to alternative minimum tax.
We classify interest and penalties related to uncertain tax positions as current income tax expense. Amounts recorded related to interest and penalties totaled $42 million in 2009, $88 million in 2008, including $29 million recorded as goodwill, $12 million for the period October 11, 2007 through December 31, 2007 and $43 million for the period January 1, 2007 through October 10, 2007 (all amounts after tax).
Noncurrent liabilities included a total of $361 million and $198 million in accrued interest at December 31, 2009 and 2008, respectively. Effective in 2009, the federal income tax benefit on the interest accrued on uncertain tax positions is recorded as accumulated deferred income taxes. Such amounts were previously reported net as a reduction of the liability for uncertain tax positions.
The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in the consolidated balance sheet, during the years ended December 31, 2009 and 2008:
Of the balance at December 31, 2009, $1.474 billion represents tax positions for which the uncertainty relates to the timing of recognition in tax returns. The disallowance of such positions would not affect the effective tax rate, but would accelerate the payment of cash to the taxing authority to an earlier period.
With respect to tax positions for which the ultimate deductibility is uncertain (permanent items), should we sustain such positions on income tax returns previously filed, liabilities recorded would be reduced by $164 million, resulting in increased income from continuing operations and a favorable impact on the effective tax rate.
We filed a claim in 2006 for refund of income taxes and related interest paid in 2005 associated with IRS audits of 1993 and 1994 tax returns of a discontinued operation. The expected refund was recognized in the adoption of accounting guidance related to uncertain tax positions. We received the refund, totaling $98 million, in February 2009.
We do not expect the total amount of liabilities recorded related to uncertain tax positions will significantly increase or decrease within the next 12 months.
9. INCOME TAXES
The components of our income tax expense (benefit) applicable to continuing operations are as follows:
Reconciliation of income taxes computed at the US federal statutory rate to income tax expense:
Texas Margin Tax
In May 2006, the Texas legislature enacted a new law that reformed the Texas franchise tax system and replaced it with a new tax system, referred to as the Texas margin tax. The Texas margin tax has been determined to be an income tax for accounting purposes. In June 2007, an amendment to this law was enacted that included clarifications and technical changes to the provisions of the tax calculation. In the 2007 Predecessor period, we recorded a deferred tax benefit of $70 million, essentially all of which related to changes in the rate at which a tax credit is calculated as specified in the new law. Of the total $70 million deferred tax benefit, $32 million was recognized in the Competitive Electric segment results and $38 million was recognized in the Corporate and Other nonsegment results.
Deferred Income Tax Balances
Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2009 and 2008 balance sheet dates are as follows:
(a) See Note 14.
At December 31, 2009 we had $438 million of alternative minimum tax credit carryforwards (AMT) available to offset future tax payments. The AMT credit carryforwards have no expiration date. At December 31, 2009, we had net operating loss (NOL) carryforwards for federal income tax purposes of $1.206 billion that expire between 2023 and 2028. The NOL carryforwards can be used to offset future taxable income. We expect to utilize all of our NOL carryforwards prior to their expiration dates.
The component of deferred income tax liabilities referred to as “basis difference in Oncor partnership” arose as a result of the sale of noncontrolling interests in Oncor (see Note 15) at which time Oncor became a partnership for US federal income tax purposes. The amount of this basis difference at the date of the transaction represented our interest (approximately 80%) in the net deferred tax liabilities related to Oncor’s individual operating assets and liabilities. The remaining net deferred tax liabilities associated with Oncor ($321 million at December 31, 2009) that are attributable to the noncontrolling interests have been reclassified as other noncurrent liabilities (see Note 25).
The income tax effects of the components included in accumulated other comprehensive income at December 31, 2009 and 2008 totaled a net deferred tax asset of $165 million and $207 million, respectively.
See Note 8 for discussion regarding accounting for uncertain tax positions.
10. OTHER INCOME AND DEDUCTIONS
(a) As part of the 2004 sale of the assets of TXU Fuel, TCEH entered into a transportation agreement with the new owner, intended to be market-price based, to transport natural gas to TCEH’s generation plants. Because of the continuing involvement in the business through the transportation agreement, the pretax gain of $375 million related to the sale was deferred and being recognized over the eight-year life of the transportation agreement, and the business was not accounted for as a discontinued operation. The remaining $218 million deferred gain was eliminated as part of purchase accounting related to the Merger. Reported in Corporate and Other activities.
(b) Includes $23 million for reversal of a use tax accrual, related to periods prior to the Merger, due to a state ruling in 2009 (reported in Competitive Electric segment) and $21 million for reversal of excess exit liabilities recorded in connection with the termination of outsourcing arrangements (see Notes 2 and 20) (reported in Competitive Electric ($11 million) and Regulated Delivery segments ($10 million)).
(c) Reported in Competitive Electric segment.
(d) Represents insurance recovery for damage to mining equipment. Reported in Competitive Electric segment.
(e) Impairment of land expected to be sold in the next 12 months. Reported in Competitive Electric segment.
(f) Represents reserve established against amounts due (excluding termination related costs) from subsidiaries of Lehman Brothers Holdings Inc. (Lehman) arising from commodity hedging and trading activities. There are no open positions with these subsidiaries. Reported in Competitive Electric segment.
(g) Includes post-Merger consulting expenses related to optimizing business performance. Reported in Corporate and Other activities.
(h) Represents costs associated with termination and refinancing of a rail car lease. Reported in Competitive Electric segment.
(i) Predecessor period includes $30 million of previously deferred costs, consisting primarily of professional fees for tax, legal and other advisory services, in connection with certain previously anticipated strategic transactions (including expected financings) that were no longer expected to be consummated as a result of the Merger. Reported in Corporate and Other activities.
(j) In 2004, we recorded a charge of $157 million for leases of certain natural gas-fueled combustion turbines, net of estimated sublease revenues, that were no longer operated for our own benefit. In the third quarter of 2007, a $48 million reduction in the related liability was recorded to reflect new subleases entered into in October 2007 (reported in the Competitive Electric segment results). The remaining $59 million liability was eliminated as part of purchase accounting as we intend to operate these assets for our own benefit.
11. TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM
TXU Energy participates in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with transfers and servicing accounting standards (see Note 1 for discussion of a new accounting standard effective in the first quarter of 2010). Under the program, TXU Energy (originator) sells trade accounts receivable to TXU Receivables Company, which is a special purpose entity created for the purpose of purchasing receivables from the originator and is a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp. TXU Receivables Company sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions (the funding entities). As discussed below, Oncor also participated in the program prior to the Merger.
The maximum amount currently available under the accounts receivable securitization program is $700 million, and program funding totaled $383 million at December 31, 2009. Under the terms of the program, available funding was reduced by the total of $83 million of customer deposits held by the originator at December 31, 2009 because TCEH’s credit ratings were lower than Ba3/BB-.
All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Changes in the amount of funding under the program, through changes in the amount of undivided interests sold by TXU Receivables Company, reflect seasonal variations in the level of accounts receivable, changes in collection trends and other factors such as changes in sales prices and volumes. TXU Receivables Company has issued subordinated notes payable to the originator for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originator that was funded by the sale of the undivided interests. The balance of the subordinated notes payable, which is eliminated in consolidation, totaled $463 million and $268 million at December 31, 2009 and 2008, respectively.
The discount from face amount on the purchase of receivables from the originator principally funds program fees paid to the funding entities. The program fees, which are also referred to as losses on sale of the receivables under transfers and servicing accounting standards, consist primarily of interest costs on the underlying financing. The discount also funds a servicing fee paid by TXU Receivables Company to EFH Corporate Services Company (Service Co.), a direct wholly-owned subsidiary of EFH Corp., which provides recordkeeping services and is the collection agent for the program.
Program fee amounts, which are reported in SG&A expenses, were as follows:
The trade accounts receivable balance reported in the December 31, 2009 consolidated balance sheet includes $846 million face amount of retail trade accounts receivable sold net of proceeds from the sale of undivided interests in those receivables totaling $383 million. Funding under the program decreased $33 million in 2009, increased $53 million in 2008 and decreased $264 million in 2007. Funding increases or decreases under the program are reflected as operating cash flow activity in the statement of cash flows. The carrying amount of the retained interests in the accounts receivable balance approximated fair value due to the short-term nature of the collection period.
In connection with the Merger, the accounts receivable securitization program was amended. Concurrently with the amendment, the financial institutions required that Oncor repurchase all of the receivables it had previously sold to TXU Receivables Company, which totaled $254 million. Oncor funded such repurchases through borrowings under its credit facility of $113 million, and a related subordinated note receivable from TXU Receivables Company in the amount of $141 million was canceled. Amounts related to Oncor’s trade accounts receivable for the period from January 1, 2007 through October 10, 2007 totaled $6 million in program fees and $27 million in operating cash flows provided, exclusive of the $113 million used by Oncor to repurchase its receivables at the time of the Merger.
Activities of TXU Receivables Company were as follows:
The program, which expires in October 2013, may be terminated upon the occurrence of a number of specified events, including if the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days collection outstanding ratio exceed stated thresholds, and the funding entities do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables. In addition, the program may be terminated if TXU Receivables Company or the EFH Corp. subsidiary acting as collection agent defaults in any payment with respect to debt in excess of $50,000 in the aggregate for such entities, or if TCEH, any affiliate of TCEH acting as collection agent other than the EFH Corp. subsidiary, any parent guarantor of the originator or the originator shall default in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for such entities. As of December 31, 2009, there were no such events of termination.
Upon termination of the program, liquidity would be reduced as collections of sold receivables would be used by TXU Receivables Company to repurchase the undivided interests from the funding entities instead of purchasing new receivables. The level of cash flows would normalize in approximately 16 to 30 days.
The subordinated notes issued by TXU Receivables Company are subordinated to the undivided interests of the funding entities in the purchased receivables.
Trade Accounts Receivable
Gross trade accounts receivable at December 31, 2009 and 2008 included unbilled revenues of $546 million and $505 million, respectively.
Allowance for Uncollectible Accounts Receivable
12. SHORT-TERM BORROWINGS AND LONG-TERM DEBT
Short-Term Borrowings
At December 31, 2009, we had outstanding short-term borrowings of $1.569 billion at a weighted average interest rate of 2.50%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $953 million for TCEH and $616 million for Oncor.
At December 31, 2008, we had outstanding short-term borrowings of $1.237 billion at a weighted average interest rate of 3.41%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $900 million for TCEH and $337 million for Oncor.
Credit Facilities
Our credit facilities with cash borrowing and/or letter of credit availability at December 31, 2009 are presented below. The facilities are all senior secured facilities of the authorized borrower.
(a) Facility used for letters of credit and borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount includes $141 million of commitments from Lehman that are only available from the fronting banks and the swingline lender and excludes $26 million of requested cash draws that have not been funded by Lehman. All outstanding borrowings under this facility at December 31, 2009 bear interest at LIBOR plus 3.5%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 0.50% of the average daily unused portion of the facility.
(b) Facility used for issuing letters of credit for general corporate purposes, including, but not limited to, providing collateral support under hedging arrangements and other commodity transactions that are not eligible for funding under the TCEH Commodity Collateral Posting Facility. The borrowings under this facility were drawn at the inception of the facility, are classified as long-term debt, and except for $115 million related to a letter of credit drawn in June 2009, have been retained as restricted cash. Letters of credit totaling $736 million issued as of December 31, 2009 are supported by the restricted cash, and the remaining letter of credit availability totals $399 million.
(c) Pursuant to PUCT rules, TCEH is required to maintain available capacity under its credit facilities to assure adequate credit worthiness of TCEH’s REP subsidiaries, including the ability to return retail customer deposits, if necessary. As a result, at December 31, 2009, the total availability under the TCEH credit facilities should be further reduced by $228 million.
(d) Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 600 million MMBtu as of December 31, 2009. As of December 31, 2009, there were no borrowings under this facility. See “TCEH Senior Secured Facilities” below for additional information.
(e) Facility used by Oncor for its general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount excludes $122 million of commitments from Lehman. All outstanding borrowings under this facility at December 31, 2009 bear interest at LIBOR plus 0.350%, and a facility fee is payable (currently at a rate per annum equal to 0.125%) on the commitments under the facility. The interest rate and facility fee rate per annum declined in June 2009 from LIBOR plus 0.425% and 0.150%, respectively, due to a two notch upgrade in Oncor’s credit ratings by Moody’s.
Long-Term Debt
At December 31, 2009 and 2008, the long-term debt consisted of the following:
(a) These series are in the multiannual interest rate mode and are subject to mandatory tender prior to maturity on the mandatory remarketing date. On such date, the interest rate and interest rate period will be reset for the bonds.
(b) Interest rates in effect at December 31, 2009. These series are in a daily interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.
(c) Interest rate in effect at December 31, 2009. This series is in a weekly interest rate mode and is classified as long-term as it is supported by long-term irrevocable letters of credit.
(d) Amount represents unamortized fair value adjustments recorded under purchase accounting.
(e) Interest rate swapped to fixed on $16.30 billion principal amount.
(f) Interest rates in effect at December 31, 2009.
(g) Interest rate in effect at December 31, 2009, excluding a quarterly maintenance fee of approximately $11 million. See “Credit Facilities” above for more information.
(h) 2009 amounts exclude $56 million and $87 million of the original and Series B notes, respectively, that are held by EFH Corp. and Intermediate Holding and eliminated in consolidation. See discussion of debt exchanges below.
(i) 2009 amounts exclude $9 million, $6 million and $3 million of the Series P, Series Q and Series R notes, respectively, that are held by Intermediate Holding and eliminated in consolidation. See discussion of debt exchanges below.
(j) This financing is secured and will be serviced with $115 million in restricted cash drawn in June 2009 by the beneficiary of a letter of credit. The issuer elected not to extend the expiration date of the letter of credit, and TCEH elected to allow the drawing in lieu of reissuing the letter of credit under the TCEH Revolving Credit Facility. The remaining $104 million of the prepayment (net of $11 million of debt service payments) is included in other current assets and other noncurrent assets on the balance sheet.
(k) Secured with first priority lien as discussed under “Oncor Secured Revolving Credit Facility” below.
(l) These bonds are nonrecourse to Oncor and were issued to securitize a regulatory asset.
(m) Includes zero and $3 million at December 31, 2009 and 2008, respectively, representing debt of the EFH Corp. parent entity.
EFH Corp. 10% Senior Secured Notes Issued in 2010 - In January 2010, EFH Corp. issued $500 million aggregate principal amount of 10.00% Senior Secured Notes due 2020 (the EFH Corp. 10% Notes). The notes will mature on January 15, 2020, and interest is payable in cash in arrears on January 15 and July 15 of each year at a fixed rate of 10.00% per annum with the first interest payment due on July 15, 2010. Other than interest rate and maturity date, the notes have the same guarantees and collateral and substantially the same other terms and conditions as the EFH Corp. 9.75% Notes.
Before January 15, 2013, EFH Corp. may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of its EFH Corp. 10% Notes from time to time at a redemption price of 110.000% of the aggregate principal amount of the notes, plus accrued and unpaid interest, if any. EFH Corp. may redeem the notes at any time prior to January 15, 2015 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. EFH Corp. may also redeem the notes, in whole or in part, at any time on or after January 15, 2015, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control (as described in the indenture), EFH Corp. may be required to offer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest, if any.
The EFH Corp. 10% Notes were issued in a private placement and have not been registered under the Securities Act. EFH Corp. has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFH Corp. 10% Notes (except for provisions relating to the transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable exchange notes for the EFH Corp. 10% Notes. EFH Corp. has agreed to use commercially reasonable efforts to cause the exchange offer to be completed or, if required under special circumstances, to have one or more shelf registration statements declared effective, within 360 days after the issue date of the notes. If this obligation is not satisfied (a Registration Default), the annual interest rate on the notes will increase by 25 basis points for the first 90-day period during which a Registration Default continues, and thereafter the annual interest rate on the notes will increase by 50 basis points for the remaining period during which the Registration Default continues. If the Registration Default is cured, the interest rate on the notes will revert to the original level.
Debt-Related Activity in 2009 - Repayments of long-term debt in 2009 totaling $396 million represented principal payments at scheduled maturity dates as well as other repayments totaling $50 million, principally related to capitalized leases. Payments at scheduled amortization or maturity dates included $165 million repaid under the TCEH Initial Term Loan Facility, $104 million of Oncor transition bond principal payments, $65 million repaid under a TCEH promissory note, $9 million repaid under the TCEH Delayed Draw Term Loan Facility and $3 million of EFH Corp. senior notes.
Increases in long-term debt during 2009 totaling $522 million consisted of increased borrowings under the TCEH Delayed Draw Term Loan Facility, which was fully drawn as of July 2009, to fund expenditures related to construction of new generation facilities and environmental upgrades of existing lignite/coal-fueled generation facilities. In addition, long-term debt increased as a result of EFH Corp. increasing, through the payment-in-kind (PIK) election, the principal amount of its 11.25%/12.00% Senior Toggle Notes due November 2017 (EFH Corp. Toggle Notes) by $309 million and TCEH increasing, through the PIK election, the principal amount of its 10.50%/11.25% Senior Toggle Notes due November 2016 (TCEH Toggle Notes) by $202 million, in each case, in lieu of making cash interest payments.
Debt Exchanges - In October 2009, EFH Corp., Intermediate Holding and EFIH Finance, a wholly-owned subsidiary of Intermediate Holding, commenced offers to exchange up to approximately $4.9 billion principal amount of EFH Corp. 10.875% Senior Notes due November 2017 (EFH Corp. 10.875% Notes) and EFH Corp. Toggle Notes (collectively with the EFH Corp. 10.875% Notes, the EFH Corp. Senior Notes), EFH Corp. Series P, Q and R Notes and TCEH 10.25% Notes due November 2015 (the TCEH 10.25% Notes and collectively, with the EFH Corp. 10.875% Notes, Toggle Notes and Series P, Q and R Notes, the Old Notes) for up to $3.0 billion of new senior secured notes, with up to $1.35 billion to be issued by EFH Corp. and up to $1.65 billion to be issued by Intermediate Holding and EFIH Finance (the EFIH Co-Issuers). The purpose of the debt exchanges was to reduce the outstanding principal amount and extend the weighted average maturity of our long-term debt.
The debt exchange transactions, which closed in November 2009, resulted in the tendering of $357 million principal amount of Old Notes in exchange for $115 million principal amount of 9.75% Senior Secured Notes issued by EFH Corp. (the EFH Corp. 9.75% Notes) and $141 million principal amount of 9.75% Senior Secured Notes issued by Intermediate Holding and EFIH Finance (the EFIH Notes). The EFH Corp. 9.75% Notes and EFIH Notes will mature in October 2019, with interest payable in cash semi-annually in arrears on April 15 and October 15.
The EFH Corp. 9.75% Notes are fully and unconditionally guaranteed on a joint and several basis by EFC Holdings and Intermediate Holding. The guarantee from Intermediate Holding is secured by the pledge of all membership interests and other investments Intermediate Holding owns or holds in Oncor Holdings or any of Oncor Holdings’ subsidiaries (the Collateral). The guarantee from EFC Holdings is not secured. The EFIH Notes are secured by the Collateral on a parity lien basis with the EFH Corp. 9.75% Notes.
The EFH Corp. 9.75% Notes and EFIH Notes are senior obligations of each issuer and rank equally in right of payment with all senior indebtedness of each issuer and are senior in right of payment to any future subordinated indebtedness of each issuer. The EFH Corp. 9.75% Notes are effectively subordinated to any indebtedness of EFH Corp. secured by assets of EFH Corp. to the extent of the value of the assets securing such indebtedness and structurally subordinated to all indebtedness and other liabilities of EFH Corp.’s non-guarantor subsidiaries. The EFIH Notes are effectively senior to all unsecured indebtedness of the EFIH Co-Issuers, to the extent of the value of the Collateral, and will be effectively subordinated to any indebtedness of the EFIH Co-Issuers secured by assets of the EFIH Co-Issuers other than the Collateral, to the extent of the value of the assets securing such indebtedness. Furthermore, the EFIH Notes will be structurally subordinated to all indebtedness and other liabilities of Intermediate Holding’s subsidiaries (other than EFIH Finance), including Oncor Holdings and its subsidiaries.
The guarantees of the EFH Corp. 9.75% Notes are the general senior obligations of each guarantor and rank equally in right of payment with all existing and future senior indebtedness of each guarantor. The guarantee from Intermediate Holding is effectively senior to all unsecured indebtedness of Intermediate Holding to the extent of the value of the Collateral. The guarantee will be effectively subordinated to all secured indebtedness of each guarantor secured by assets other than the Collateral to the extent of the value of the assets securing such indebtedness and will be structurally subordinated to any existing and future indebtedness and liabilities of EFH Corp.’s subsidiaries that are not guarantors.
The EFH Corp. 9.75% Notes and EFIH Notes and indentures governing such notes restrict the issuers and their restricted subsidiaries’ ability to, among other things, make restricted payments, incur debt and issue preferred stock, incur liens, permit dividend and other payment restrictions on restricted subsidiaries, merge, consolidate or sell assets and engage in transactions with affiliates. These covenants are subject to a number of limitations and exceptions. The notes and indentures also contain customary events of default, including, among others, failure to pay principal or interest on the notes when due. If certain events of default occur and are continuing under a series of notes and the related indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes of such series may declare the principal amount of the notes of such series to be due and payable immediately.
There currently are no restricted subsidiaries under the indenture related to the EFIH Notes (other than EFIH Finance, which has no assets). Oncor Holdings, the immediate parent of Oncor, and its subsidiaries are unrestricted subsidiaries under the EFIH indenture and, accordingly, will not be subject to any of the restrictive covenants in the indenture.
The respective issuers may redeem the EFH Corp. 9.75% Notes and EFIH Notes, in whole or in part, at any time on or after October 15, 2014, at specified redemption prices, plus accrued and unpaid interest, if any. In addition, before October 15, 2012, the respective issuers may redeem up to 35% of the aggregate principal amount of each series of the notes from time to time at a redemption price of 109.750% of the aggregate principal amount of such series of notes, plus accrued and unpaid interest, if any, with the net cash proceeds of certain equity offerings. The respective issuers may also redeem each series of the notes at any time prior to October 15, 2014 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. Upon the occurrence of a change of control (as described in the indenture), the respective issuers may be required to offer to repurchase each series of the notes at 101% of their principal amount, plus accrued and unpaid interest, if any.
Debt-Related Activity in 2008 - Repayments of long-term debt in 2008 totaling $1.167 billion represented principal payments at scheduled maturity dates as well as the remarketing of $242 million principal amount of pollution control revenue bonds discussed below, repayment of $413 million of borrowings under the TCEH Commodity Collateral Posting Facility, which fully repaid borrowings under the facility, and other repayments totaling $48 million, principally related to leases. Payments at scheduled maturity dates included $200 million of EFH Corp. senior notes, $165 million repaid under the TCEH Initial Term Loan Facility, and $99 million of Oncor transition bond principal payments.
Increases in long-term debt during 2008 totaling $3.185 billion consisted of issuances of senior secured notes issued by Oncor with an aggregate principal amount of $1.500 billion (see discussion below under “Oncor Senior Secured Notes”), borrowings under the TCEH Delayed Draw Term Loan Facility of $1.412 billion to fund expenditures related to the development of new generation facilities and the environmental retrofit program for existing lignite/coal-fueled generation facilities, the remarketing of $242 million principal amount of pollution control revenue bonds discussed immediately below and $31 million of additional borrowings under the TCEH Commodity Collateral Posting Facility.
In June 2008, TCEH remarketed the Brazos River Authority Pollution Control Revenue Bonds Series 2001A due in October 2030 and Series 2001D-1 due in May 2033 with aggregate principal amounts of $71 million and $171 million, respectively. The bonds were previously in a floating rate mode that reset weekly and were backed by two letters of credit in an aggregate amount of $247 million. As a result of the remarketing, the bonds were fixed to maturity at an interest rate of 8.25%, and the two letters of credit were cancelled. The bonds are redeemable at par beginning July 1, 2018 and are redeemable with a make-whole premium prior to July 1, 2018. These bonds were remarketed with a covenant package similar to the notes discussed below under “TCEH Senior Notes.”
Maturities - Long-term debt maturities as of December 31, 2009 are as follows (includes Oncor’s transition bond semi-annual payments):
(a) Long-term debt maturities for EFH Corp. (parent entity) total $7.328 billion, including $18 million held by Intermediate Holding that is not included above.
(b) Unamortized fair value discount for EFH Corp. (parent entity) totals $(599) million.
TCEH Senior Secured Facilities - Borrowings under the TCEH Initial Term Loan Facility, the TCEH Delayed Draw Term Loan Facility, the TCEH Revolving Credit Facility and the TCEH Letter of Credit Facility, which totaled $22.357 billion at December 31, 2009, bear interest at per annum rates equal to, at TCEH’s option, (i) adjusted LIBOR plus 3.50% or (ii) a base rate (the higher of (1) the prime rate as announced from time to time by the administrative agent of the facilities and (2) the federal funds effective rate plus 0.50%) plus 2.50%. There is a margin adjustment mechanism in relation to term loans, revolving loans and letter of credit fees under which the applicable margins may be reduced based on the achievement of certain leverage ratio levels; there was no such reduction based upon December 31, 2009 levels. The applicable rate on borrowings under the facilities as of December 31, 2009 is provided in the long-term debt table and in the discussion of short-term borrowings above and reflects LIBOR-based borrowings.
In August 2009, the TCEH Senior Secured Facilities were amended to reduce the existing first lien capacity under the TCEH Senior Secured Facilities by $1.25 billion in exchange for the ability for TCEH to issue up to an additional $4 billion of secured notes or loans ranking junior to TCEH’s first lien obligations, provided that:
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such notes or loans mature later than the latest maturity date of any of the initial term loans under the TCEH Senior Secured Facilities, and
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any net cash proceeds from any such issuances are used (i) in exchange for, or to refinance, repay, retire, refund or replace indebtedness of TCEH or (ii) to acquire, directly or indirectly, all or substantially all of the property and assets or business of another person or to finance the purchase price, cost of design, acquisition, construction, repair, restoration, replacement, expansion, installation or improvement of certain fixed or capital assets.
In addition, the amended facilities permit TCEH to, among other things:
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issue new secured notes or loans, which may include, in each case, indebtedness secured on a pari passu basis with the obligations under the TCEH Senior Secured Facilities, so long as, in each case, among other things, the net cash proceeds from any such issuance are used to prepay certain loans under the TCEH Senior Secured Facilities at par;
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agree with individual lenders to extend the maturity of their term loans or extend or refinance their revolving credit commitments under the TCEH Senior Secured Facilities, and pay increased interest rates or otherwise modify the terms of their loans or revolving commitments in connection with such an extension, and
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exclude from the financial maintenance covenant under the TCEH Senior Secured Facilities any new debt issued that ranks junior to TCEH’s first lien obligations under the TCEH Senior Secured Facilities.
Under the terms of the TCEH Senior Secured Facilities, the commitments of the lenders to make loans to TCEH are several and not joint. Accordingly, if any lender fails to make loans to TCEH, TCEH’s available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the TCEH Senior Secured Facilities.
The TCEH Senior Secured Facilities are unconditionally guaranteed jointly and severally on a senior secured basis by EFC Holdings, and subject to certain exceptions, each existing and future direct or indirect wholly-owned US restricted subsidiary of TCEH. The TCEH Senior Secured Facilities, including the guarantees thereof, certain commodity hedging transactions and the interest rate swaps described under “TCEH Interest Rate Swap Transactions” below are secured by (a) substantially all of the current and future assets of TCEH and TCEH’s subsidiaries who are guarantors of such facilities and (b) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.
The TCEH Initial Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of such facility (approximately $41 million quarterly), with the balance payable in October 2014. The TCEH Delayed Draw Term Loan Facility is required to be repaid in equal quarterly installments beginning in December 2009 in an aggregate annual amount equal to 1% of the actual principal outstanding under such facility as of such date, with the balance payable in October 2014. Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time until October 2013. The TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility will mature in October 2014 and December 2012, respectively.
The TCEH Senior Secured Facilities contain customary negative covenants, restricting, subject to certain exceptions, TCEH and TCEH’s restricted subsidiaries from, among other things:
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incurring additional debt;
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incurring additional liens;
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entering into mergers and consolidations;
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selling or otherwise disposing of assets;
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making dividends, redemptions or other distributions in respect of capital stock;
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making acquisitions, investments, loans and advances, and
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paying or modifying certain subordinated and other material debt.
In addition, the TCEH Senior Secured Facilities contain a maintenance covenant that prohibits TCEH and its restricted subsidiaries from exceeding a maximum consolidated secured leverage ratio and to observe certain customary reporting requirements and other affirmative covenants.
The TCEH Senior Secured Facilities contain certain customary events of default for senior leveraged acquisition financings, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments.
TCEH Senior Notes - The indebtedness under TCEH’s and TCEH Finance’s 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015 (Series B) (collectively, TCEH 10.25% Notes) bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.25% per annum payable in cash. The indebtedness under the TCEH Toggle Notes bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.50% per annum for cash interest and at a fixed rate of 11.25% per annum for PIK interest. For any interest periods until November 2012, the issuers may elect to pay interest on the notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new TCEH Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. TCEH made the PIK election for both interest payments in 2009, increasing the principal amount. Once TCEH makes a PIK election, the election is valid for each succeeding interest payment period until TCEH revokes the election.
The TCEH 10.25% and Toggle Notes (collectively, the TCEH Senior Notes) are fully and unconditionally guaranteed on a joint and several basis by TCEH’s direct parent, EFC Holdings (which owns 100% of TCEH and its subsidiary guarantors), and by each subsidiary that guarantees the TCEH Senior Secured Facilities.
Before November 1, 2010, the issuers may redeem with the cash proceeds of certain equity offerings up to 35% of the aggregate principal amount of the TCEH 10.25% and Toggle Notes from time to time at a redemption price of 110.250% and 110.500%, respectively, of their respective aggregate principal amount plus accrued and unpaid interest, if any. The issuers may also redeem the TCEH Senior Notes at any time prior to November 1, 2011 and 2012, respectively, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. The issuers may redeem the TCEH Senior Notes, in whole or in part, at any time on or after November 1, 2011 and 2012, respectively, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFC Holdings or TCEH, the issuers may be required to offer to repurchase the TCEH Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.
The indenture for the TCEH Senior Notes contains a number of covenants that, among other things, restrict, subject to certain exceptions, the Co-Issuers’ and their restricted subsidiaries’ ability to:
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make restricted payments;
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incur debt and issue preferred stock;
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create liens;
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enter into mergers or consolidations;
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sell or otherwise dispose of certain assets;
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permit dividend and other payment restrictions on restricted subsidiaries, and
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engage in certain transactions with affiliates.
The indenture also contains customary events of default, including failure to pay principal or interest on the notes when due, among others. If certain events of default occur and are continuing under the indenture, the trustee or the holders of at least 30% in principal amount of the notes may declare the principal amount on the notes to be due and payable immediately.
EFH Corp. Senior Notes - Borrowings under EFH Corp.’s 10.875% Notes bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.875% per annum payable in cash. Borrowings under EFH Corp.’s 11.250%/12.000% Senior Toggle Notes due November 1, 2017 bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 11.250% per annum for cash interest and at a fixed rate of 12.000% per annum for PIK Interest. For any interest period until November 1, 2012, EFH Corp. may elect to pay interest on the notes, at EFH Corp.’s option (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new EFH Corp. Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. EFH Corp. made the PIK election for both interest payments in 2009, increasing the principal amount of the EFH Corp. Toggle Notes. Once EFH Corp. makes a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. revokes the election.
The EFH Corp. Senior Notes are fully and unconditionally guaranteed on a joint and several basis by EFC Holdings and Intermediate Holding.
Before November 1, 2010, EFH Corp. may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of its 10.875% and Toggle Notes from time to time at a redemption price of 110.875% and 111.250%, respectively, of their respective aggregate principal amounts, plus accrued and unpaid interest, if any. EFH Corp. may redeem the notes at any time prior to November 1, 2012 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. EFH Corp. may also redeem the notes, in whole or in part, at any time on or after November 1, 2012, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFH Corp., EFH Corp. must offer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest, if any.
The indenture for the EFH Corp. Senior Notes contains a number of covenants that, among other things, restrict, subject to certain exceptions, EFH Corp.’s and its restricted subsidiaries’ ability to:
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make restricted payments;
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incur debt and issue preferred stock;
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create liens;
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enter into mergers or consolidations;
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sell or otherwise dispose of certain assets;
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permit dividend and other payment restrictions on restricted subsidiaries, and
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engage in certain transactions with affiliates.
The indenture also contains customary events of default, including failure to pay principal or interest on the notes or the guarantees when due, among others. If an event of default occurs under the indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes may declare the principal amount on the notes to be due and payable immediately.
Intercreditor Agreement - In October 2007, TCEH entered into an intercreditor agreement with Citibank, N.A. and five secured commodity hedge counterparties (the Secured Commodity Hedge Counterparties). In connection with the August 2009 amendment to the TCEH Secured Facilities described above, the intercreditor agreement was amended and restated (as amended and restated, the “Intercreditor Agreement”) to take into account, among other things, the possibility that TCEH could issue notes and/or loans secured by collateral (other than the collateral that secures the TCEH Senior Secured Facilities) that ranks on parity with, or junior to, TCEH’s existing first lien obligations under the TCEH Senior Secured Facilities. The Intercreditor Agreement provides that the lien granted to the Secured Commodity Hedge Counterparties will rank pari passu with the lien granted with respect to the collateral of the secured parties under the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties will be entitled to share, on a pro rata basis, in the proceeds of any liquidation of such collateral in connection with a foreclosure on such collateral in an amount provided in the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties will have voting rights with respect to any amendment or waiver of any provision of the Intercreditor Agreement that changes the priority of the Secured Commodity Hedge Counterparties’ lien on such collateral relative to the priority of lien granted to the secured parties under the TCEH Senior Secured Facilities or the priority of payments to the Secured Commodity Hedge Counterparties upon a foreclosure and liquidation of such collateral relative to the priority of the lien granted to the secured parties under the TCEH Senior Secured Facilities.
TCEH Interest Rate Swap Transactions - As of December 31, 2009, TCEH has entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of $16.30 billion of senior secured term loans of TCEH were exchanged for interest payments at fixed rates of between 7.3% and 8.3% on debt maturing from 2010 to 2014. Swaps on $1.25 billion principal amount of senior secured debt expired in 2009. Interest rate swaps on an aggregate of $15.05 billion were being accounted for as cash flow hedges related to variable interest rate cash flows until August 29, 2008, at which time these swaps were dedesignated as cash flow hedges as a result of the intent to change the variable interest rate terms of the hedged debt (from three-month LIBOR to one-month LIBOR) in connection with the planned execution of interest rate basis swaps (discussed immediately below) to further reduce the fixed borrowing costs. Based on the fair value of the positions, the cumulative unrealized mark-to-market net losses related to these interest rate swaps totaled $431 million (pre-tax) at the dedesignation date and was recorded in accumulated other comprehensive income. This balance will be reclassified into net income as interest on the hedged debt is reflected in net income. No ineffectiveness gains or losses were recorded.
As of December 31, 2009, TCEH has entered into interest rate basis swap transactions pursuant to which payments at floating interest rates of three-month LIBOR on an aggregate of $16.25 billion principal amount of senior secured term loans of TCEH were exchanged for floating interest rates of one-month LIBOR plus spreads ranging from 0.0625% to 0.353%. These transactions include swaps entered into in the year ended December 31, 2009 related to an aggregate $9.55 billion principal amount of senior secured term loans of TCEH and reflect the expiration of swaps in the year ended December 31, 2009 that related to an aggregate $6.345 billion principal amount of senior secured term loans of TCEH.
The interest rate swap counterparties are proportionately secured by the same collateral package granted to the lenders under the TCEH Senior Secured Facilities. Subsequent to the dedesignation in August 2008 discussed above, changes in the fair value of such swaps are being reported in the income statement in interest expense and related charges, and such unrealized mark-to-market value changes totaled $696 million in net gains in the year ended December 31, 2009 and $1.477 billion in net losses in the year ended December 31, 2008. The cumulative unrealized mark-to-market net liability related to the swaps totaled $1.212 billion at December 31, 2009, of which $194 million (pre-tax) was reported in accumulated other comprehensive income.
See Note 18 for discussion of collateral investments related to certain of these interest rate swaps.
Oncor Secured Revolving Credit Facility - Oncor has a $2.0 billion credit facility to be used for its working capital and general corporate purposes, including issuances of commercial paper and letters of credit (Oncor Revolving Credit Facility). Oncor may request increases in the commitments under the facility in any amount up to $500 million, subject to the satisfaction of certain conditions. Amounts borrowed under the facility, once repaid, can be reborrowed by Oncor from time to time until October 10, 2013. Under the terms of this credit facility, the commitments of the lenders to make loans to Oncor are several and not joint. Accordingly, if any lender fails to make loans to Oncor, Oncor’s available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the Oncor Revolving Credit Facility. Oncor secured this credit facility with a first priority lien on certain of its transmission and distribution assets. Oncor also secured all of its existing long-term debt securities (excluding the transition bonds) with the same lien in accordance with the terms of those securities. The lien contains customary provisions allowing Oncor to use the assets in its business, as well as to replace and/or release collateral as long as the market value of the aggregate collateral is at least 115% of the aggregate secured debt. The lien may be terminated at Oncor’s option upon the termination of Oncor’s credit facility. Borrowings under this credit facility totaled $616 million and $337 million at December 31, 2009 and 2008, respectively. The applicable rate on borrowings under this credit facility as of December 31, 2009 was 0.58% (see detail provided in the credit facilities table above).
The credit facility contains customary covenants for facilities of this type, restricting, subject to certain exceptions, Oncor and its subsidiary from, among other things:
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incurring additional liens;
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entering into mergers and consolidations;
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selling certain assets, and
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making acquisitions and investments in subsidiaries.
In addition, the credit facility requires that Oncor maintain a consolidated senior debt-to-capitalization ratio of no greater than 0.65 to 1.00 and observe certain customary reporting requirements and other affirmative covenants.
The credit facility contains certain customary events of default for facilities of this type, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments under the facility.
Oncor Senior Secured Notes - In September 2008, Oncor issued and sold senior secured notes with an aggregate principal amount of $1.500 billion consisting of $650 million aggregate principal amount of 5.95% senior secured notes maturing in September 2013, $550 million aggregate principal amount of 6.80% senior secured notes maturing in September 2018 and $300 million aggregate principal amount of 7.50% senior secured notes maturing in September 2038. Oncor used the net proceeds of approximately $1.487 billion from the sale of the Oncor notes to repay most of its borrowings under its credit facility as well as for general corporate purposes. The Oncor notes are secured by the first priority lien described above. If the lien is terminated, the notes will cease to be secured obligations of Oncor and will become senior unsecured general obligations of Oncor.
Interest on these notes is payable in cash semiannually in arrears on March 1 and September 1 of each year. Oncor may redeem the notes, in whole or in part, at any time, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. The notes also contain customary events of default, including failure to pay principal or interest on the notes when due.
13. COMMITMENTS AND CONTINGENCIES
Contractual Commitments
At December 31, 2009, we had noncancellable commitments under energy-related contracts, leases and other agreements as follows:
(a) On the basis of current expectations of demand from electricity customers as compared with capacity and take-or-pay payments, management does not consider it likely that any material payments will become due for electricity not taken beyond capacity payments.
At December 31, 2009, future minimum lease payments under both capital leases and operating leases are as follows:
(a) Includes operating leases with initial or remaining noncancellable lease terms in excess of one year.
In February 2010, a capital lease related to a mining railroad spur was terminated, and we purchased the related spur for $63 million. At December 31, 2009, the balance of the capital lease liability was $63 million. The assets were recorded at cost as property, plant and equipment and will be depreciated over their remaining useful lives, the weighted average of which is 23 years.
Rent reported as operating costs, fuel costs and SG&A expenses totaled $92 million for both years ended December 31, 2009 and 2008, $26 million for the period October 11, 2007 through December 31, 2007 and $66 million for the Predecessor period January 1, 2007 through October 10, 2007.
Commitment to Fund Demand Side Management Initiatives
In connection with the Merger, Texas Holdings committed to spend $100 million over the five-year period ending December 31, 2012 on demand side management or other energy efficiency initiatives. This commitment is expected to be funded by EFH Corp. and/or its subsidiaries other than Oncor. This commitment is in addition to over $300 million to be invested by Oncor for similar initiatives. See Note 6 for other provisions of the stipulation, including a similar commitment made by Oncor.
Capital Expenditures
Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As one of the provisions of this stipulation, Oncor committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions. See Note 6.
Guarantees
We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. Material guarantees are discussed below.
Disposed TXU Gas operations - In connection with the sale of TXU Gas in October 2004, EFH Corp. agreed to indemnify Atmos Energy Corporation (Atmos), until October 1, 2014, for up to $500 million for any liability related to assets retained by TXU Gas, including certain inactive gas plant sites not acquired by Atmos, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. The maximum aggregate amount under these indemnities that we may be required to pay is $1.9 billion. To date, we have not been required to make any payments to Atmos under any of these indemnity obligations, and no such payments are currently anticipated.
Residual value guarantees in operating leases - We are the lessee under various operating leases that guarantee the residual values of the leased assets. At December 31, 2009, the aggregate maximum amount of residual values guaranteed was approximately $45 million with an estimated residual recovery of approximately $49 million. These leased assets consist primarily of mining equipment, rail cars and vehicles. The average life of the residual value guarantees under the lease portfolio is approximately four years.
See Note 12 for discussion of guarantees and security for certain of our indebtedness.
Letters of Credit
At December 31, 2009, TCEH had outstanding letters of credit under its credit facilities totaling $736 million as follows:
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$379 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions;
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$208 million to support floating rate pollution control revenue bond debt with an aggregate principal amount of $204 million (the letters of credit are available to fund the payment of such debt obligations and expire in 2014);
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$65 million for collateral funding transactions with counterparties to interest rate swap agreements related to TCEH debt (see Note 18), and
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$84 million for miscellaneous credit support requirements.
Litigation Related to Generation Facilities
In September 2007, an administrative appeal challenging the order of the TCEQ issuing the air permit for construction and operation of the Oak Grove generation facility in Robertson County, Texas was filed in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse the TCEQ’s approval of the Oak Grove air permit and the TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments, and remand the matter back to TCEQ for further proceedings. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before the TCEQ and the State Office of Administrative Hearings (SOAH) seeking to challenge the TCEQ’s issuance of the Oak Grove air permit and asking the District Court to remand the matter to the SOAH for further proceedings. Finally, the plaintiffs in these two additional lawsuits filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to the SOAH for further proceedings. One of the plaintiffs asked the District Court to consolidate all these proceedings, and the Attorney General of Texas, on behalf of TCEQ, filed pleas to the jurisdiction seeking dismissal of all but the administrative appeal. In May 2009, the District Court dismissed the claims that contest the merits of the TCEQ’s permitting decision, but declined to dismiss the claims that contest the process by which the TCEQ handled the permit application. Oak Grove Management Company LLC (a subsidiary of TCEH) has subsequently intervened in these proceedings and has filed its own pleas to the jurisdiction asking the court to dismiss the remaining collateral attack claims. In October 2009, one of the plaintiffs ended its legal challenge to the permit. In December 2009, the Attorney General and Oak Grove Management Company LLC filed pleadings asking the court to dismiss the administrative appeal challenging the permit for want of prosecution by the plaintiffs. In January 2010, the court denied that request and set the case for a hearing on the merits on June 16, 2010. We believe the Oak Grove air permit granted by the TCEQ was issued in accordance with applicable law. There can be no assurance that the outcome of these matters will not adversely impact the Oak Grove project.
In June and September 2008, administrative appeals were filed in the State District Court of Travis County, Texas to challenge the administrative action of the TCEQ Executive Director in issuing an air permit alteration for the previously-permitted construction and operation of the Sandow 5 generation facility in Milam County, Texas, and the failure of the TCEQ to overturn that administrative action. Plaintiffs asked that the District Court reverse the issuance of the permit alteration. The Attorney General of Texas, on behalf of TCEQ, is defending the issuance of the permit alteration. Sandow Power (a subsidiary of TCEH) intervened in support of the TCEQ. The District Court issued its ruling in November 2009 upholding the TCEQ’s issuance of the permit alteration. The plaintiffs did not appeal the court’s order by the deadline for such appeal. Thus, the matter has concluded favorably for EFH Corp.
In February 2010, the Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Big Brown generation facility. This notice is similar to the notice that Luminant received in July 2008 with respect to its Martin Lake generation facility. We cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.
In July 2008, Alcoa Inc. filed a lawsuit in the State District Court of Milam County, Texas against Luminant Generation and Luminant Mining (wholly-owned subsidiaries of TCEH), later adding EFH Corp., a number of its subsidiaries, Texas Holdings and Texas Energy Future Capital Holdings LLC as parties to the suit. The lawsuit makes various claims concerning the operation of the Sandow Unit 4 generation facility and the Three Oaks lignite mine, including claims for breach of contract, breach of fiduciary duty, fraud, tortious interference, civil conspiracy and conversion. The plaintiff requests money damages of no less than $500 million, declaratory judgment, rescission and other forms of equitable relief. An agreed scheduling order is currently in place setting trial for May 2010. While we are unable to estimate any possible loss or predict the outcome of this litigation, we believe the plaintiff’s claims made in this litigation are without merit and, accordingly, intend to vigorously defend this litigation.
Regulatory Investigations and Reviews
In June 2008, the EPA issued a request for information to TCEH under EPA’s authority under Section 114 of the Clean Air Act. The stated purpose of the request is to obtain information necessary to determine compliance with the Clean Air Act, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received a large and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently received a notice of violation from the EPA, which has in some cases progressed to litigation or settlement. The company is cooperating with the EPA and is responding in good faith to the EPA’s request, but is unable to predict the outcome of this matter.
Other Proceedings
In addition to the above, we are involved in various other legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect on our financial position, results of operations or cash flows.
Labor Contracts
Certain personnel engaged in TCEH and Oncor activities are represented by labor unions and covered by collective bargaining agreements with varying expiration dates. In October 2009, new one-year labor agreements were reached covering bargaining unit personnel engaged in the lignite-fueled generation operations, the lignite mining operations and natural gas-fueled generation operations. In August 2008, a new labor agreement effective until August 2010 was reached covering bargaining unit personnel engaged in nuclear generation. In February 2008, a new three-year contract was ratified covering bargaining unit personnel engaged in Oncor’s operations. In June 2009, a group of approximately 50 Oncor employees voted to decertify the labor union as their representative. In December 2009, a group of approximately 350 Oncor employees elected to be represented by a labor union. We expect that any changes in collective bargaining agreements will not have a material effect on our financial position, results of operations or cash flows; however, we are unable to predict the ultimate outcome of these labor negotiations.
Environmental Contingencies
The federal Clean Air Act, as amended (Clean Air Act) includes provisions which, among other things, place limits on SO2 and NOx emissions produced by electricity generation plants. The capital requirements of the company have not been significantly affected by the requirements of the Clean Air Act. In addition, all air pollution control provisions of the 1999 Restructuring Legislation have been satisfied.
We must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. We believe that we are in compliance with current environmental laws and regulations; however, the impact, if any, of changes to existing regulations or the implementation of new regulations is not determinable.
The costs to comply with environmental regulations can be significantly affected by the following external events or conditions:
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enactment of state or federal regulations regarding CO2 and other greenhouse gas emissions;
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other changes to existing state or federal regulation regarding air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters, including revisions to CAIR currently being developed by the EPA as a result of court rulings discussed in Note 3, and
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the identification of sites requiring clean-up or the filing of other complaints in which we may be asserted to be potential responsible parties.
Nuclear Insurance
Nuclear insurance includes liability coverage, property damage, decontamination and premature decommissioning coverage and accidental outage and/or extra expense coverage. The liability coverage is governed by the Price-Anderson Act (Act), while the property damage, decontamination and premature decommissioning coverage are promulgated by the rules and regulations of the NRC. We intend to maintain insurance against nuclear risks as long as such insurance is available. The company is self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Such losses could have a material adverse effect on our financial condition and results of operations and cash flows.
With regard to liability coverage, the Act provides financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $12.5 billion and requires nuclear generation plant operators to provide financial protection for this amount. The US Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $12.5 billion limit for a single incident mandated by the Act. As required, the company provides this financial protection for a nuclear incident at Comanche Peak resulting in public bodily injury and property damage through a combination of private insurance and industry-wide retrospective payment plans. As the first layer of financial protection, the company has $375 million of liability insurance from American Nuclear Insurers (ANI), which provides such insurance on behalf of a major stock insurance company pool, Nuclear Energy Liability Insurance Association. The second layer of financial protection is provided under an industry-wide retrospective payment program called Secondary Financial Protection (SFP).
Under the SFP, in the event of an incident at any nuclear generation plant in the US, each operating licensed reactor in the US is subject to an assessment of up to $117.5 million plus a 3% insurance premium tax, subject to increases for inflation every five years. Assessments are limited to $17.5 million per operating licensed reactor per year per incident. The company’s maximum potential assessment under the industry retrospective plan would be $235 million (excluding taxes) per incident but no more than $35 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $375 million per accident at any nuclear facility. The SFP and liability coverage are not subject to any deductibles.
With respect to nuclear decontamination and property damage insurance, the NRC requires that nuclear generation plant license-holders maintain at least $1.06 billion of such insurance and require the proceeds thereof to be used to place a plant in a safe and stable condition, to decontaminate it pursuant to a plan submitted to and approved by the NRC before the proceeds can be used for plant repair or restoration or to provide for premature decommissioning. The company maintains nuclear decontamination and property damage insurance for Comanche Peak in the amount of $2.25 billion (subject to $5 million deductible per accident), above which the company is self-insured. This insurance coverage consists of a primary layer of coverage of $500 million provided by Nuclear Electric Insurance Limited (NEIL), a nuclear electric utility industry mutual insurance company and $1.75 billion of premature decommissioning coverage also provided by NEIL.
The company maintains Accidental Outage Insurance through NEIL to cover the additional costs of obtaining replacement electricity from another source if one or both of the units at Comanche Peak are out of service for more than twelve weeks as a result of covered direct physical damage. The coverage provides for weekly payments of $3.5 million for the first fifty-two weeks and $2.8 million for the next 110 weeks for each outage, respectively, after the initial twelve-week waiting period. The total maximum coverage is $490 million per unit. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service at the same time as a result of the same accident.
If NEIL’s losses exceeded its reserves for the applicable coverage, potential assessments in the form of a retrospective premium call could be made up to ten times annual premiums. The company maintains insurance coverage against these potential retrospective premium calls.
Also, under the NEIL policies, if there were multiple terrorism losses occurring within a one-year time frame, NEIL would make available one industry aggregate limit of $3.2 billion plus any amounts it recovers from other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply.
14. SHAREHOLDERS’ EQUITY
Successor
Equity Contributions, Issuances and Repurchases - In connection with the Merger, Texas Holdings made an aggregate cash equity contribution of approximately $8.3 billion to EFH Corp. in exchange for EFH Corp. issuing approximately 1.658 billion shares of its common stock to Texas Holdings. In the year ended December 31, 2008 and the period from October 11, 2007 to December 31, 2007, EFH Corp. issued an aggregate of approximately 5.5 million and 2.0 million shares of its common stock, respectively, to, or for the benefit of, certain of its officers, directors and employees for an aggregate consideration of $27.4 million and $9.8 million, respectively. The 2008 amounts include shares previously subscribed. In addition, in the years ended December 31, 2009 and 2008, EFH Corp. issued an aggregate of 1.5 million and 1.7 million shares, respectively, of its common stock to, or for the benefit of, certain officers, directors and employees as stock-based compensation as discussed in Note 22. In 2008, EFH Corp. repurchased 0.8 million shares of its common stock from employees primarily upon termination of employment or amendment of agreements, for an aggregate consideration of $3.9 million.
Effect of Sale of Noncontrolling Interests - The total amount of proceeds from the sale of noncontrolling interests in Oncor discussed in Note 15 was less than the carrying value of the interests sold by $265 million, which reflects the fact that Oncor’s carrying value after purchase accounting is based on the Merger value, while the noncontrolling interests sale value does not include a control premium. This difference was accounted for as a reduction of shareholders’ equity.
During the preparation of our December 31, 2009 financial statements, we determined that deferred income taxes related to EFH Corp.’s interest in Oncor should have been recorded upon the sale of noncontrolling interests in November 2008. Accordingly, the December 31, 2008 balance of noncurrent accumulated deferred income tax liabilities has been increased by $141 million (from the $5.926 billion previously reported) and shareholders’ equity at that date has been decreased by the same amount (from the $3.532 billion deficit previously reported). The recognition of the deferred tax liability is the result of applying rules for income tax accounting related to outside basis differences. This error did not affect net income or cash flows previously reported.
Dividend Restrictions - The indentures governing the EFH Corp. Senior Notes, 9.75% Notes, and 10% Notes include covenants that, among other things and subject to certain exceptions, restrict our ability to pay dividends or make other distributions in respect of our capital stock. Accordingly, essentially all of our net income is restricted from being used to make distributions on our common stock unless such distributions are expressly permitted under these indentures and/or after such distributions, on a pro forma basis, after giving effect to such payment, EFH Corp.’s consolidated leverage ratio is equal to or less than 7.0 to 1.0. For purposes of this calculation, “consolidated leverage ratio” is defined as the ratio of consolidated total indebtedness (as defined in the indenture) to Adjusted EBITDA, in each case, consolidated with its subsidiaries other than Oncor Holdings and its subsidiaries. In addition, the indenture governing the EFIH Notes generally restricts Intermediate Holding from making any distribution to EFH Corp. for the ultimate purpose of making a distribution to Texas Holdings unless at the time, and after giving effect to such distribution, Intermediate Holding’s consolidated leverage ratio is equal to or less than 6.0 to 1.0. Under the indenture governing the EFIH Notes, the term “consolidated leverage ratio” is defined as the ratio of consolidated total indebtedness (as defined in the indenture) to Adjusted EBITDA on a consolidated basis.
The TCEH Senior Secured Facilities generally restrict TCEH from making any distribution to any of its parent companies for the ultimate purpose of making a distribution to Texas Holdings unless at the time, and after giving effect to such distribution, its consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. In addition, the TCEH Senior Secured Facilities and indenture governing the TCEH Senior Notes generally restrict TCEH’s ability to make distributions or loans to any of its parent companies, EFC Holdings and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and indenture governing the TCEH Senior Notes. Those agreements generally permit TCEH to make unlimited distributions or loans to its parent companies for corporate overhead costs, SG&A expenses, taxes and principal and interest payments. In addition, those agreements contain certain investment and dividend baskets that would allow TCEH to make additional distributions and/or loans to its parent companies up to the amount of such baskets. At December 31, 2009, EFH Corp. notes payable to TCEH totaled $1.406 billion.
In addition, under applicable law, we would be prohibited from paying any dividend to the extent that immediately following payment of such dividend, there would be no statutory surplus or we would be insolvent.
EFH Corp. has not paid any cash dividends subsequent to the Merger.
Shareholder Actions - In May 2009, the shareholders of EFH Corp. approved the change of the stated capital of EFH Corp.’s common stock, no par value per share, to an amount equal to $0.001 for each outstanding share of common stock, resulting in total stated value of outstanding common stock of $2 million. Also in May 2009, EFH Corp.’s board of directors approved a decrease in additional paid-in capital of the same amount and the allocation of $0.001 per share to stated value of common stock upon issuance of any authorized but unissued shares of common stock that may occur from time to time, with the remainder of any amounts received for such shares allocated to additional paid-in capital.
Common Stock Registration Rights - The Sponsor Group and certain other investors entered into a registration rights agreement with EFH Corp. upon closing of the Merger. Pursuant to this agreement, in certain instances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.’s common stock owned directly or indirectly by them under the Securities Act. In certain instances, the Sponsor Group and certain other investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.’s common stock under the Securities Act that it may undertake.
See Note 22 for discussion of stock-based compensation plans.
Predecessor
Declaration of Dividend - At its August 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 per share, which was paid October 1, 2007 to shareholders of record on September 7, 2007. At its May 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 per share, which was paid on July 2, 2007 to shareholders of record on June 1, 2007. At its February 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 a share, payable April 2, 2007 to shareholders of record on March 2, 2007.
Thrift Plan - The Thrift Plan is an employee savings plan under which we matched a portion of employees’ contributions of their earnings with a contribution in shares of EFH Corp. common stock. Contributions to the Thrift Plan are held by an unconsolidated trust. At October 10, 2007, the Thrift Plan had an obligation of $201 million outstanding in the form of a note payable to EFH Corp. (LESOP note). Proceeds from the issuance of the note, which EFH Corp. purchased from a third-party lender in 1990, were used by the Thrift Plan trustee to purchase EFH Corp.’s common stock on the open market for the purpose of satisfying future matching requirements. These shares (LESOP shares) were held by the Thrift Plan trustee under the leveraged employee stock ownership provision of the Thrift Plan. The note receivable had been classified as a reduction of common stock equity, and the principal and related interest was being amortized as a component of LESOP-related expense.
The Thrift Plan used dividends received on the LESOP shares held and contributions from us, if required, to repay interest and principal on the LESOP note; such contributions totaled $14 million for the period from January 1, 2007 through October 10, 2007.
On the date of the Merger, the Thrift Plan trustee held approximately 5.7 million shares of EFH Corp.’s common stock. These shares were converted to cash at $69.25 per share in connection with the closing of the Merger. The Thrift Plan trustee used the cash proceeds to repay the LESOP note, and then made an additional allocation of the remaining cash proceeds to eligible Thrift Plan participants.
The table below reflects the changes in the number of Predecessor common stock shares outstanding:
15. NONCONTROLLING INTERESTS
In November 2008, equity interests in Oncor were sold to Texas Transmission for $1.254 billion in cash. Equity interests were also indirectly sold to certain members of Oncor’s board of directors and its management team. Accordingly, after giving effect to all equity issuances, as of December 31, 2009, Oncor’s ownership was as follows: 80.03% held indirectly by EFH Corp., 0.22% held indirectly by Oncor’s management and board of directors and 19.75% held by Texas Transmission.
The proceeds (net of closing costs) of $1.253 billion received by Oncor from Texas Transmission and the members of Oncor management upon completion of these transactions were distributed ultimately to EFH Corp. Under the terms of certain financing arrangements of EFH Corp. and TCEH, upon such distribution, under certain circumstances, EFH Corp. (parent entity) is required to repay certain outstanding intercompany loans from TCEH. In November 2008, EFH Corp. repaid the $253 million balance of notes payable to TCEH that related to payments of principal and interest on EFH Corp. (parent entity) debt.
See Note 14 for discussion of amounts recorded as a reduction of shareholders’ equity as a result of the sale of Oncor interests.
Of the noncontrolling interests balance reported in the December 31, 2009 and 2008 consolidated balance sheets, $1.363 billion and $1.355 billion, respectively, related to Oncor’s noncontrolling interests. The noncontrolling interests balance reported in the December 31, 2009 consolidated balance sheet represented the proportional share of Oncor’s net assets at the date of the transaction less $96 million representing the noncontrolling interests’ share of Oncor’s net losses for the periods subsequent to the transaction (including the goodwill impairment charge), net of $58 million in cash distributions.
In connection with the filing of a combined operating license application with the NRC for two new nuclear generation units, in January 2009, TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, known as Comanche Peak Nuclear Power Company LLC, to further the development of the two new nuclear generation units using MHI’s US-Advanced Pressurized Water Reactor technology. Under the terms of the joint venture agreement, a subsidiary of TCEH owns an 88% interest in the venture and a subsidiary of MHI owns a 12% interest. This joint venture is a variable interest entity, and a subsidiary of TCEH is considered the primary beneficiary.
16. FAIR VALUE MEASUREMENTS
Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use a “mid-market” valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the market approach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.
We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:
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Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 assets and liabilities include exchange traded commodity contracts. For example, a significant number of our derivatives are NYMEX futures and swaps transacted through clearing brokers for which prices are actively quoted.
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Level 2 valuations use inputs, in the absence of actively quoted market prices, that are observable for the asset or liability, either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means and other valuation inputs. For example, our Level 2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes are available.
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Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assets and liabilities include certain derivatives whose values are derived from pricing models that utilize multiple inputs to the valuations, including inputs that are not observable or easily corroborated through other means.
We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.
In utilizing broker quotes, we attempt to obtain multiple quotes from brokers that are active in the commodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker’s publication policy, recent trading volume trends and various other factors. In addition, for valuation of interest rate swaps, we use a combination of dealer provided market valuations (generally non-binding) and Bloomberg valuations based on month-end interest rate curves and standard rate swap valuation models.
Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including commodity prices, volatility factors, discount rates and other inputs. Additionally, when there is not a sufficient amount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Those valuation models are generally used in developing long-term forward price curves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.
With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.
At December 31, 2009, assets and liabilities measured at fair value on a recurring basis consisted of the following:
(a) Level 3 assets and liabilities consist primarily of complex long-term power purchase and sales agreements, including long-term wind generation purchase contracts and certain natural gas positions (collars) in the long-term hedging program.
(b) Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities.
(c) The nuclear decommissioning trust investment is included in the Investments line on the balance sheet. See Note 19.
See Note 21 for fair value measurements related to pension and OPEB plan assets.
At December 31, 2008, assets and liabilities measured at fair value on a recurring basis consisted of the following:
(a) Level 3 assets and liabilities consist primarily of complex long-term power purchase and sales agreements, including long-term wind generation purchase contracts and certain natural gas positions (collars) in the long-term hedging program.
(b) The nuclear decommissioning trust investment is included in the Investments line on the balance sheet. See Note 19.
Commodity contracts consist primarily of natural gas, electricity, fuel oil and coal derivative instruments entered into for hedging purposes and include physical contracts that have not been designated “normal” purchases or sales. See Note 18 for further discussion regarding the company’s use of derivative instruments.
Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 12 for discussion of interest rate swaps.
Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of the nuclear generation units. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.
The following table presents the changes in fair value of the Level 3 assets and liabilities (all related to commodity contracts) for the years ended December 31, 2009 and 2008:
(a) Substantially all changes in values of commodity contracts are reported in the income statement in net gain (loss) from commodity hedging and trading activities.
(b) Settlements represent reversals of unrealized mark-to-market valuations of these positions previously recognized in net income. Purchases and issuances reflect option premiums paid or received.
(c) Includes transfers due to changes in the observability of significant inputs used in valuing derivatives. Transfers in are assumed to transfer in at the beginning of the quarter and transfers out at the end of the quarter, which is when the assessments are performed. Any changes in value during the period are reported as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities.
(d) Includes unrealized gains and losses of instruments held at the end of the period.
17. FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS
The carrying amounts and related estimated fair values of significant nonderivative financial instruments were as follows:
(a) Fair value determined in accordance with accounting standards related to the determination of fair value.
(b) Excludes capital leases.
See Notes 16 and 18 for discussion of accounting for financial instruments that are derivatives.
18. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES
Risk Management Hedging Strategy
We enter into physical and financial derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage commodity price risk and interest rate risk exposure. Our principal activities involving derivatives consist of a long-term hedging program and the hedging of interest costs on our long-term debt. See Note 16 for a discussion of the fair value of all derivatives.
Long-Term Hedging Program - TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricity sales and related cash flows. In ERCOT, the wholesale price of electricity is highly correlated to the price of natural gas. Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas over the next five years. These transactions are intended to hedge a majority of electricity price exposure related to expected baseload generation for this period. Changes in the fair value of the instruments under the long-term hedging program are reported in the income statement in net gain (loss) from commodity hedging and trading activities.
Interest Rate Swap Transactions - Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate debt to a fixed basis, thereby hedging future interest costs and related cash flows. Interest rate basis swaps are used to effectively reduce the hedged borrowing costs. Changes in the fair value of the swaps are recorded as unrealized gains and losses in interest expense and related charges. See Note 12 for additional information about these and other interest rate swap agreements.
Other Commodity Hedging and Trading Activity - In addition to the long-term hedging program, TCEH enters into derivatives, including electricity, natural gas, fuel oil and coal instruments, generally for shorter-term hedging purposes. To a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in natural gas and electricity markets.
The following table provides detail of commodity and other derivative contractual assets and liabilities, substantially all arising from mark-to-market accounting, as reported in the balance sheet at December 31, 2009:
As of December 31, 2009, there were no derivative positions accounted for as cash flow or fair value hedges.
Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet and totaled $358 million and $190 million in net liabilities at December 31, 2009 and 2008, respectively, which do not include the collateral investments related to certain interest rate swaps and commodity positions discussed immediately below. Reported amounts as presented in the above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements. This presentation can result in significant volatility in derivative assets and liabilities because we may enter into offsetting positions with the same counterparties, resulting in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.
In early 2009, we entered into collateral funding transactions with counterparties to certain interest rate swap agreements related to TCEH debt. Under the terms of these transactions, which we elected to enter into as a cash management measure, as of December 31, 2009, EFH Corp. (parent) has posted $400 million in cash and TCEH has posted $65 million in letters of credit to the counterparties, with the outstanding balance of such collateral earning interest. TCEH had also entered into commodity hedging transactions with one of these counterparties, and under an arrangement effective August 2009, both the interest rate swaps and certain of the commodity hedging transactions with the counterparty are under the same derivative agreement, which continues to be secured by a first-lien interest in the assets of TCEH. We are not required to post any additional collateral to these counterparties, regardless of the net mark-to-market liability under the applicable derivative agreement, and the applicable counterparty will return the cash collateral to the extent the mark-to-market liability under the applicable derivative agreement falls below the funded amount, subject to a $50 million minimum transfer amount. At December 31, 2009, the collateral posted approximated the net mark-to-market liability of the related derivatives. Under the agreements, the counterparties are to return any remaining collateral, along with accrued and unpaid interest, on March 31, 2010. The cash collateral was recorded as an investment and is presented in the balance sheet (including accrued interest) as a separate line item under current assets.
The following table presents the pre-tax effect of derivatives not under hedge accounting on net income, including realized and unrealized effects:
Amounts reported in the income statement in net gain (loss) from commodity hedging and trading activities include net “day one” mark-to-market losses of $2 million, $68 million and $8 million in the 2009, 2008 and 2007 Successor periods, respectively, and $201 million in the 2007 Predecessor period. Substantially all of these losses arose from a related series of derivative transactions entered into under the long-term hedging program. The 2007 Predecessor period amount is net of a $30 million “day one” gain associated with a long-term power purchase agreement.
A multi-year power sales agreement was entered into with Alcoa Inc. in the 2007 Predecessor period. The agreement was determined to be a derivative and resulted in a “day one” mark-to-market loss of $235 million. The agreement was entered into concurrently with the transfer of an air permit from Alcoa Inc. to a subsidiary of ours as well as other agreements with Alcoa Inc. that provide, among other things, access to real property and a supply of lignite fuel, all of which provides value to us by providing the right and ability to develop, construct and operate the new lignite-fueled generation unit at Sandow. In consideration of this right and ability, the initial “day one” loss of the sales agreement, as well as a $29 million below market value of a related interim power sales agreement entered into in late 2006, were recorded as part of the construction work-in-process asset balance for the Sandow unit.
The following tables present the pre-tax effect of derivative instruments accounted for as cash flow hedges on net income (loss) and other comprehensive income (loss) (OCI) for the year ended December 31, 2009:
There were no ineffectiveness net gains or losses related to transactions designated as cash flow hedges in the year ended December 31, 2009.
Accumulated other comprehensive income related to cash flow hedges at December 31, 2009 totaled $128 million in net losses (after-tax), substantially all of which relates to interest rate swaps. We expect that $59 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of December 31, 2009 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.
Derivative Volumes - The following table presents the gross notional amounts of derivative volumes at December 31, 2009:
(a) Represents gross notional forward sales, purchases and options of fixed and basis (price point) transactions in the long-term hedging program. The net amount of these transactions, excluding basis transactions, is 1.6 billion MMBtu.
Credit Risk-Related Contingent Features
The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of those agreements require the posting of collateral if our credit rating is downgraded by one or more of the credit rating agencies; however, due to our below investment grade ratings, substantially all of such collateral posting requirements are already effective.
As of December 31, 2009, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $687 million. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $152 million as of December 31, 2009. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, as of December 31, 2009, the remaining related liquidity requirement would have totaled $20 million after reduction for net accounts receivable and derivative assets under netting arrangements.
In addition, certain derivative agreements that are collateralized primarily with asset liens include indebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. As of December 31, 2009, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $1.482 billion (before consideration of the amount of assets under the liens). The liquidity exposure associated with these liabilities was reduced by cash collateral and letters of credit posted with counterparties totaling $489 million as of December 31, 2009. If all the credit risk-related contingent features related to these derivatives, including amounts related to cross-default provisions, had been triggered as of December 31, 2009, the remaining related liquidity requirement would have totaled $480 million after reduction for derivative assets under netting arrangements (before consideration of the amount of assets under the liens). See Note 12 for a description of other obligations that are supported by asset liens.
As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $2.169 billion at December 31, 2009. This amount is before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets under related liens.
Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amounts to be posted if the features are triggered. These provisions include material adverse change, performance assurance, and other clauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosed above exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.
Concentrations of Credit Risk
TCEH has significant concentrations of credit risk with the counterparties to its derivative contracts. As of December 31, 2009, total credit risk exposure to all counterparties related to derivative contracts totaled $4.0 billion. The net exposure to those counterparties totaled $1.3 billion after taking into effect master netting arrangements, setoff provisions and collateral. As of December 31, 2009, the credit risk exposure to the banking and financial sector represented more than 90% of the total credit risk exposure. As of December 31, 2009, the largest net exposure to a single counterparty totaled $536 million. Exposure to the banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because substantially all of this exposure is with counterparties with credit ratings of “A” or better. However, this concentration increases the risk that a default by any of these counterparties would have a material adverse effect on our financial condition and results of operations.
The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies specify authorized risk mitigation tools including, but not limited to, use of standardized master netting contracts and agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material adverse changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.
19. INVESTMENTS
The investments balance consists of the following:
(a) A controlling interest in this previously consolidated subsidiary was sold in August 2009.
Nuclear Decommissioning Trust
Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor’s customers as a delivery fee surcharge over the life of the plant and deposited in the trust fund. Net gains and losses on investments in the trust fund are offset by a corresponding adjustment to a regulatory asset/liability. A summary of investments in the fund follows:
(a) Includes realized gains and losses of securities sold.
(b) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 4.44% and 3.77% and an average maturity of 7.8 years and 8.0 years at December 31, 2009 and 2008, respectively.
(c) The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index.
Debt securities held at December 31, 2009 mature as follows: $82 million in one to five years, $32 million in five to ten years and $102 million after ten years.
Assets Related to Employee Benefit Plans
The majority of these assets represent cash surrender values of life insurance policies that are purchased to fund liabilities under deferred compensation plans. We pay the premiums and are the beneficiary of these life insurance policies. As of December 31, 2009 and 2008, the face amount of these policies totaled $322 million and $481 million, and the net cash surrender values totaled $124 million and $155 million, respectively. Changes in cash surrender value are netted against premiums paid. Other investment assets held to satisfy deferred compensation liabilities are recorded at fair value.
20. TERMINATION OF OUTSOURCING ARRANGEMENTS
In connection with the closing of the Merger, EFH Corp., TCEH and Oncor commenced a review, under the change of control provision, of certain outsourcing arrangements with Capgemini, Capgemini America, Inc. and Capgemini North America, Inc. (collectively, CgE). In 2008, EFH Corp. and TCEH executed a Separation Agreement with CgE. Simultaneous with the execution of that Separation Agreement, Oncor entered into a substantially similar Separation Agreement with CgE. The Separation Agreements principally provide for (i) notice of termination of each of the Master Framework Agreements, dated as of May 17, 2004, as each has been amended, between Capgemini and each of TCEH and Oncor and the related service agreements under each of the Master Framework Agreements and (ii) termination of the joint venture arrangements between EFH Corp. (and its applicable subsidiaries) and CgE. Under the Master Framework Agreements and related services agreements, Capgemini provided outsourced support services, including information technology, customer care and billing, human resources, procurement and certain finance and accounting activities. As a result, during 2008:
•
the 2.9% limited partnership interest in Capgemini owned by a subsidiary of EFH Corp. was redeemed in exchange for the termination of the license that was granted by a subsidiary of EFH Corp. to Capgemini at the time the Master Framework Agreements were executed in order for Capgemini to use certain information technology assets primarily consisting of capitalized software to provide services to us and third parties;
•
we received approximately $70 million in exchange for the termination of a purchase option agreement pursuant to which our subsidiaries had the right to “put” to Capgemini (and Capgemini had the right to “call” from a subsidiary of ours) our 2.9% limited partnership interest in Capgemini and the licensed assets upon the expiration of the Master Framework Agreements in 2014 or, in some circumstances, earlier, and
•
Capgemini repaid $25 million (plus accrued interest) representing all amounts owed by Capgemini under the working capital loan provided by us in July 2004.
Under the Separation Agreements, the parties also entered into a mutual release of all claims under the Master Framework Agreements and related services agreements and the joint venture agreements, subject to certain defined exceptions, resulting in our receipt of $10 million in cash settlement.
The carrying value of the partnership interest was $2.9 million, and the carrying value of the purchase option was $177 million prior to the application of purchase accounting (recorded as a noncurrent asset). The effects of the termination of the outsourcing arrangements, including an accrued liability of $54 million for incremental costs to exit and transition the services, were included in the final purchase price allocation. See Note 2 for additional disclosure, including a reversal to income of a portion of the liability recorded in purchase accounting.
21. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS
EFH Corp. is the plan sponsor of the EFH Retirement Plan (Retirement Plan), which provides benefits to eligible employees of subsidiaries (participating employers). The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. The interest component of the Cash Balance Formula is variable and is determined using the yield on 30-year Treasury bonds. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs.
Effective October 1, 2007, all new employees, with the exception of employees hired by Oncor, are not eligible to participate in the Retirement Plan. New hires at Oncor are eligible to participate in the Cash Balance Formula of the Retirement Plan. It is our policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations.
We also have supplemental unfunded retirement plans for certain employees whose retirement benefits cannot fully be earned under the qualified Retirement Plan, the information for which is included below.
We offer OPEB in the form of health care and life insurance to eligible employees and their eligible dependents upon the retirement of such employees. For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree’s age and years of service.
Regulatory Recovery of Pension and OPEB Costs
PURA provides for the recovery by Oncor of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility, which in addition to Oncor’s own employees consists largely of active and retired personnel engaged in TCEH’s activities, related to service of those additional personnel prior to the deregulation and disaggregation of our businesses effective January 1, 2002. Oncor is authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Amounts deferred are ultimately subject to regulatory approval. As of December 31, 2009, Oncor had recorded regulatory assets totaling $889 million related to pension and OPEB costs, including amounts related to deferred expenses as well as amounts related to unfunded liabilities that otherwise would be recorded as other comprehensive income.
Pension and OPEB Costs Recognized as Expense
We use the calculated value method to determine the market-related value of the assets held in trust. We include the realized and unrealized gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.
Detailed Information Regarding Pension Benefits
The following information is based on December 31, 2009, 2008, 2007 and October 10, 2007 measurement dates:
(a) 2009 amount includes transfers of investments related to the salary deferral and supplemental retirement plans totaling $31 million.
(b) Amounts represent overfunded plans.
The following table provides information regarding pension plans with projected benefit obligation (PBO) and accumulated benefit obligation (ABO) in excess of the fair value of plan assets.
Pension Plan Investment Strategy and Asset Allocations
Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Equity securities are held to achieve returns in excess of passive indexes by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging international markets. Fixed income securities include primarily corporate bonds from a diversified range of companies, US Treasuries and agency securities and money market instruments. Our investment strategy for fixed income investments is to maintain a high grade portfolio of securities which assist us in managing the volatility and magnitude of plan contributions and expense.
The target asset allocation ranges of pension plan investments by asset category are as follows:
Fair Value Measurement of Pension Plan Assets
At December 31, 2009, pension plan assets measured at fair value on a recurring basis (see Note 16) consisted of the following:
(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s.
(b) Other consists primarily of US agency securities.
At December 31, 2008, pension plan assets measured at fair value on a recurring basis consisted of the following:
(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s.
(b) Other consists primarily of US agency securities.
The following table presents the changes in fair value of the Level 3 pension plan assets for the years ended December 31, 2009 and 2008:
Detailed Information Regarding Postretirement Benefits Other Than Pensions
The following OPEB information is based on December 31, 2009, 2008, 2007 and October 10, 2007 measurement dates:
The following tables provide information regarding the assumed health care cost trend rates.
OPEB Plan Investment Strategy and Asset Allocations
Our investment objective for the OPEB plan primarily follows the objectives of the Retirement Plan discussed above, while maintaining sufficient cash and short-term investments to pay near-term benefits and expenses.
Fair Value Measurement of OPEB Plan Assets
At December 31, 2009, OPEB plan assets measured at fair value on a recurring basis consisted of the following:
(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s.
(b) Other consists primarily of US agency securities.
At December 31, 2008, OPEB plan assets measured at fair value on a recurring basis consisted of the following:
(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s.
(b) Other consists primarily of US agency securities.
There was no change in the fair values of Level 3 assets in the periods presented.
Expected Long-Term Rate of Return on Assets Assumption
The Retirement Plan strategic asset allocation is determined in conjunction with the plan’s advisors and utilizes a comprehensive Asset-Liability modeling study to evaluate potential long-term outcomes of various investment strategies. The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.
Significant Concentrations of Risk
The plans’ investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to us. While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses.
Assumed Discount Rate
We selected the assumed discount rate using the Hewitt Top Quartile yield curve, which is based on actual corporate bond yields and at December 31, 2009 consisted of 111 corporate bonds rated AA or higher as reported by either Moody’s or S&P.
Amortization in 2010
In 2010, we estimate amortization of the net actuarial loss and prior service cost for the defined benefit pension plan from accumulated other comprehensive income into net periodic benefit cost will be $51 million and $1 million, respectively. We estimate amortization of the net actuarial loss, prior service credit, and transition obligation for the OPEB plan from accumulated other comprehensive income into net periodic benefit cost will be $21 million, a $1 million credit and $1 million, respectively.
Contributions in 2010
Estimated funding for calendar year 2010 totals $45 million for the Retirement Plan and $24 million for the OPEB plan.
Future Benefit Payments
Estimated future benefit payments to beneficiaries are as follows:
Thrift Plan
Our employees may participate in a qualified savings plan, the Thrift Plan. This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. The Thrift Plan included an employee stock ownership component until October 10, 2007. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such threshold may contribute from 1% to 16% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% of the first 6% of employee contributions for employees who are covered under the Cash Balance Formula of the Retirement Plan, and 75% of the first 6% of employee contributions for employees who are covered under the Traditional Retirement Plan Formula of the Retirement Plan. Effective January 1, 2006 through October 10, 2007, employees could reallocate or transfer all or part of their accumulated or future employer matching contributions to any of the plan’s other investment options. As of October 10, 2007, employer matching contributions are made in cash and may be allocated by participants to any of the plan’s investment options. Our contributions to the Thrift Plan totaled $28 million, $25 million, $6 million and $33 million in the years ended December 31, 2009 and 2008, the period October 11, 2007 through December 31, 2007 and the period January 1, 2007 through October 10, 2007, respectively. See Note 14 for additional information related to the Thrift Plan.
22. STOCK-BASED COMPENSATION
Successor - EFH Corp. 2007 Stock Incentive Plan
In December 2007, we established the 2007 Stock Incentive Plan for Key Employees of EFH Corp. and its Affiliates (2007 SIP). Incentive awards under the 2007 SIP may be granted to directors and officers and qualified managerial employees of EFH Corp. or its subsidiaries or affiliates in the form of non-qualified stock options, stock appreciation rights, restricted shares, deferred shares, shares of common stock, the opportunity to purchase shares of common stock and other awards that are valued in whole or in part by reference to, or are otherwise based on the fair market value of EFH Corp.’s shares of common stock. The 2007 SIP permits the grant of awards for 72 million shares of common stock, subject to adjustments under applicable laws for certain events, such as a change in control, and no such grants may be issued after December 26, 2017. Shares related to grants that are forfeited, terminated, cancelled, expire unexercised, withheld to satisfy tax withholding obligations, or are repurchased by the Company are available for new grants under the 2007 SIP.
Stock Options - Under the terms of the 2007 SIP, options to purchase 14.7 million, 33.1 million and 19.5 million shares of EFH Corp. common stock were granted to certain management employees in 2009, 2008 and December 2007, respectively. Of the options granted in 2009, 9.2 million were granted in exchange for previously granted options. Vested awards must be exercised within 10 years of the grant date. The options initially provided the holder the right to purchase EFH Corp. common stock for $5.00 per share. The terms of the options were fixed at grant date. The stock option awards under the 2007 SIP consist of three types of stock options. One-half of the options initially granted vest solely based upon continued employment over a specific period of time, generally five years, with the options vesting ratably on an annual basis over the period (Time-Based Options). One-half of the options initially granted vest based upon both continued employment and the achievement of targeted five-year EFH Corp. EBITDA levels (Performance-Based Options). The Performance-Based Options may also vest in part or in full upon the occurrence of certain specified liquidity events. All options remain exercisable for ten years from the date of grant. Prior to vesting, expenses are recorded if the achievement of the EBITDA levels is probable, and amounts recorded are adjusted or reversed if the probability of achievement of such levels changes. Probability of vesting is evaluated at least each quarter.
In October 2009, in consideration of the recent economic dislocation and the desire to provide incentives for retention, grantees of Performance-Based Options (excluding named executive officers and a small group of other employees) were provided an offer, which substantially all accepted, to exchange their unvested Performance-Based Options granted under the 2007 SIP with a strike price of $5.00 per share and a vesting schedule through October 2012 for new time-based stock options (Cliff-Vesting Options) granted under the 2007 SIP with a strike price of $3.50 per share (the then most recent market valuation of each share), with one-half of these options vesting in September 2012 and one-half of these options vesting in September 2014. Additionally, 3.1 million Cliff-Vesting Options were granted to certain Named Executive Officers and a small group of other employees under the 2007 SIP with a strike price of $3.50 per share, vesting in September 2014. Substantially all of this group of employees also accepted an offer to exchange half of their unvested Performance-Based Options under the 2007 SIP with a strike price of $5.00 per share and a vesting schedule through December 2012 for new time-based stock options granted under the 2007 SIP with a strike price of $3.50 per share, vesting in September 2014.
The fair value of all options granted was estimated using the Black-Scholes option pricing model and the assumptions noted in the table below. Since EFH Corp. is a private company, expected volatility is based on actual historical experience of comparable publicly-traded companies for a term corresponding to the expected life of the options. The expected life represents the period of time that options granted are expected to be outstanding and is calculated using the simplified method prescribed by the SEC Staff Accounting Bulletin No. 107. The simplified method was used since EFH Corp. does not have stock option history upon which to base the estimate of the expected life and data for similar companies was not reasonably available. The risk-free rate is based on the US Treasury security with terms equal to the expected life of the option as of the grant date.
The weighted average grant-date fair value of the Time-Based Options granted in 2009, 2008 and December 2007 was $1.32, $1.89 and $1.92 per option, respectively. The weighted-average grant-date fair value of the Performance-Based Options granted in 2009, 2008 and December 2007 ranged from $1.16 to $1.91, $1.73 to $2.25 and $1.74 to $2.09, respectively, depending upon the performance period.
Compensation expense for Time-Based Options is based on the grant-date fair value and recognized over the vesting period as employees perform services. During 2009, 2008 and the 2007 Successor period, $8.6 million, $11.9 million and less than $100,000, respectively, was recognized as expense for Time-Based Options.
As of December 31, 2009, there was approximately $48.9 million of unrecognized compensation expense related to nonvested Time-Based Options, which is expected to be recognized ratably over a remaining weighted-average period of approximately three to five years.
A summary of Time-Based Options activity is presented below:
Compensation expense for Performance-Based Options is based on the grant-date fair value and recognized over the requisite performance and service periods for each tranche of options depending upon the achievement of financial performance, or if certain liquidity events occur, as discussed above. No amounts were expensed in 2009 for Performance-Based Options because the 2009 EBITDA target was not met. Additionally, most participants’ Performance-Based Options were exchanged for Time-Based Options in 2009. Expense recognized for Performance-Based Options in 2008 totaled $8.1 million. No amounts were expensed in the 2007 Successor period for Performance-Based Options because the performance period for the first tranche of the options did not begin until January 1, 2008.
As of December 31, 2009, there was approximately $19.1 million of unrecognized compensation expense related to nonvested Performance-Based Options, which we could record as an expense over a remaining weighted-average period of approximately three to five years, subject to the achievement of financial performance being probable. A total of 4.8 million of the 2008 and none of the 2009 Performance-Based Options have vested.
A summary of Performance-Based Options activity is presented below:
Other Share and Share-Based Awards - In 2008, we granted 2.4 million deferred share awards, each of which represents the right to receive one share of EFH Corp. stock, to certain management employees who agreed to forego share-based awards that vested at the Merger date. The deferred share awards are fully vested and are payable in cash or stock upon the earlier of a change of control or separation of service. No expense was recorded in 2008 related to these awards. An additional 1.2 million deferred share awards were granted to certain management employees in 2008, approximately half of which are payable in cash or stock and the balance payable in stock; these awards vest over periods of one to five years, and $3.7 million and $2.2 million in expense was recorded in 2009 and 2008, respectively, to recognize the vesting. In 2009, 120 thousand deferred share awards were surrendered by an employee upon termination of employment. Deferred share awards that are payable in cash or stock are accounted for as liability awards; therefore, the effects of changes in value of EFH Corp. shares are recognized in earnings.
We granted 1.5 million shares of EFH Corp. stock in 2009, 1.7 million shares in 2008 and 1.0 million shares in 2007, to board members and other non-employees. The shares vest over periods of one to two years, and a portion may be settled in cash. Expense recognized in 2009, 2008 and 2007 related to these grants totaled $4.0 million, $8.2 million and $1 million, respectively.
Stock Appreciation Rights - In 2008, Oncor established the Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan (the SARs Plan) under which certain employees of Oncor and its subsidiaries may be granted stock appreciation rights (SARs) payable in cash, or in some circumstances, Oncor units. Two types of SARs may be granted under the SARs Plan. Time-based SARs (Time SARs) vest solely based upon continued employment ratably on an annual basis on each of the first five anniversaries of the grant date. Performance-based SARs (Performance SARs) vest based upon both continued employment and the achievement of a predetermined level of Oncor EBITDA over time, generally ratably over five years based upon annual Oncor EBITDA levels, with provisions for vesting if the annual levels are not achieved but cumulative two- or three-year total Oncor EBITDA levels are achieved. Time and Performance SARs may also vest in part or in full upon the occurrence of certain specified liquidity events and are exercisable only upon the occurrence of certain specified liquidity events. Since the exercisability of the Time and Performance SARs is conditioned upon the occurrence of a liquidity event, compensation expense will not be recorded until it is probable that a liquidity event will occur. Generally, awards under the SARs Plan terminate on the tenth anniversary of the grant, unless the participant’s employment is terminated earlier under certain circumstances.
In February 2009, Oncor implemented a similar plan for primarily non-employee members of Oncor’s board of directors. The terms and conditions are similar to the SARs Plan with the exception that SARs granted to non-employee board members vest in eight equal quarterly installments over a two-year period.
SARs are generally payable in cash based on the fair market value of the SAR on the date of exercise. No SARs were granted under the SARs Plan during the year ended December 31, 2009. Oncor granted 6.9 million Time SARs under the SARs Plan during the year ended December 31, 2008, and Time SARS vested at December 31, 2009 totaled 2.8 million. Oncor granted 6.9 million Performance SARs under the SARs Plan during the year ended December 31, 2008, and Performance SARs vested at December 31, 2009 totaled 1.4 million. Oncor granted 55 thousand SARs under the Director SARs Plan during the year ended December 31, 2009, and SARs vested under the Director SARs Plan at December 31, 2009 totaled 27.5 thousand. There were no SARs under either plan eligible for exercise at December 31, 2009.
Predecessor
Under our shareholder-approved long-term incentive plans, we provided discretionary awards to qualified management employees payable in EFH Corp. common stock. As presented below, the awards generally vested over a three-year period and the number of shares ultimately earned was based on the performance of EFH Corp.’s stock over the vesting period.
Awards Granted in 2007
Vesting period
Three years
Potential share pay-out as a percent of initial number of awards granted
0% to 100% (a)
Basis for pay-out percentage - actual EFH Corp. three-year share return compared to:
Share returns of companies comprising the S&P 500 Electric Utilities Index
Award type
Performance units payable in EFH Corp. stock upon vesting
(a) For a small number of employees under employment agreements, potential share pay-out as a percent of initial number of awards granted was 0% to 200%, and the number of shares distributed was based 100% on EFH Corp.’s total share return over the vesting period compared to the total returns of companies comprising the Standard & Poor’s 500 Electric Utilities Index.
In addition, we established restrictions that limited certain employees’ opportunities to liquidate vested awards. For both restricted stock and performance unit awards, dividends over the vesting periods were converted to equivalent shares of EFH Corp. common stock to be distributed upon vesting.
The determination of the fair value of stock-based compensation awards at grant date was based on a Monte Carlo simulation. The more significant assumptions used in this valuation process were as follows:
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Expected volatility of the stock price of EFH Corp. and peer group companies - expected volatility was determined based on historical stock price volatilities using daily stock price returns for the three years prior to the grant date.
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The dividend rate for EFH Corp. and peer group companies was based on the observed dividend payments over the twelve months prior to grant date.
•
Risk-free rate (three-year US Treasury securities) during the three year vesting period.
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Discount for liquidation restrictions - this factor estimated the discount for lack of marketability of vested awards due to the anticipated time for the approval and issuance of the awards, the black-out period immediately after the grant and additional holding requirements imposed on senior executives. This discount was determined based on an estimation of the cost of a protective put at the award date and is calculated using the Black-Scholes option pricing model using expected volatility assumptions based on historical and implied volatility as discussed above and a risk-free rate of return over the option period.
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Change-in-control and no-change-in-control scenarios were considered. The change-in-control scenario was based on three different change-in-control dates each assigned projected probabilities. The change-in-control value was probability weighted with the value assuming no change of control
The following table presents information about Predecessor stock-based compensation plans.
The table above reflects the weighted average fair value of the awards on grant date.
Reported expense related to the awards totaled $27 million ($18 million after-tax) in the period from January 1, 2007 through October 10, 2007. Such expenses are reported in SG&A expense, except for immaterial amounts capitalized.
The fair value of awards that vested in the period from January 1, 2007 through October 10, 2007 totaled $613 million based on the vesting date share prices.
Under the terms of the Merger Agreement, all outstanding Performance Unit awards were deemed to be vested at the date of the Merger. See Note 2.
23. RELATED PARTY TRANSACTIONS
We incur an annual management fee under the terms of a management agreement with the Sponsor Group for which we accrued $36 million, $35 million and $8 million for the years ended December 31, 2009 and 2008 and the period October 11, 2007 to December 31, 2007, respectively. The fee is reported as SG&A expense in Corporate and Other activities. Also, under terms of the management agreement, affiliates of the Sponsor Group and Lehman Brothers Inc. were paid transaction fees of $300 million for certain services provided in connection with the Merger and related transactions. A portion of these fees was included in the purchase price that was allocated to identifiable assets and liabilities as part of purchase accounting, and the remainder was reported as deferred financing costs.
At the closing of the Merger, TCEH entered into the TCEH Senior Secured Facilities and Oncor entered into a revolving credit facility, each with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of GS Capital Partners and Kohlberg Kravis Roberts & Co. L.P. (a member of the Sponsor Group) have from time to time engaged in commercial banking and financial advisory transactions with us in the normal course of business.
Affiliates of the Sponsor Group participated in debt exchange offers completed in November 2009 by EFH Corp., Intermediate Holding and EFIH Finance to exchange new senior secured notes for certain EFH Corp. and TCEH notes as discussed in Note 12 and in an EFH Corp. issuance of $500 million principal amount of senior secured notes completed in January 2010. Goldman, Sachs & Co. and KKR Capital Markets LLC acted as dealer managers and TPG Capital, L.P. served as an advisor in the exchange offers. Goldman, Sachs & Co. also acted as an initial purchaser in the issuance of senior secured notes. (See Note 12 for additional information.) These affiliates were compensated for their services in accordance with the terms of the respective agreements. These fees totaled $1 million for the year ended December 31, 2009.
Affiliates of Goldman Sachs & Co. are parties to certain commodity and interest rate hedging transactions with us in the normal course of business.
Affiliates of the Sponsor Group may sell or acquire debt or debt securities issued by us in open market transactions or through loan syndications.
24. SEGMENT INFORMATION
Our operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.
The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, the development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales to residential and business customers, all largely in Texas. These activities are conducted by TCEH. The results of this segment also include equipment salvage and resale activities related to the 2007 cancellation of the development of eight new coal-fueled generation units discussed in Note 4.
The Regulated Delivery segment is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly owned bankruptcy-remote financing subsidiary.
Corporate and Other represents the remaining nonsegment operations consisting primarily of discontinued operations, general corporate expenses and interest on EFH Corp., Intermediate Holding and EFC Holdings debt.
The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1. We evaluate performance based on income from continuing operations. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices.
(a) Amounts invested in equity investees were not material in any period presented.
(b) Assets by segment exclude investments in affiliates.
25. SUPPLEMENTARY FINANCIAL INFORMATION
Regulated Versus Unregulated Operations
(a) Includes unregulated cost of fuel consumed of $1.269 billion in 2009, $1.604 billion in 2008, $255 million in the period from October 11, 2007 through December 31, 2007 and $868 million in the period from January 1, 2007 through October 10, 2007. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations.
Interest Expense and Related Charges
Restricted Cash
Inventories by Major Category
Property, Plant and Equipment
Depreciation expense totaled $1.454 billion, $1.355 billion, $297 million and $467 million for the years ended December 31, 2009 and 2008, the period October 11, 2007 through December 31, 2007 and the period January 1, 2007 through October 10, 2007, respectively, including $394 million, $330 million, $63 million and $235 million, respectively, related to Oncor.
We began depreciating two recently completed lignite-fueled generation units in the fourth quarter 2009.
Assets related to capitalized leases included above totaled $167 million at both December 31, 2009 and 2008, net of accumulated depreciation.
Asset Retirement Obligations
These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to the recognition of the asset retirement costs for nuclear decommissioning, as all costs are recoverable through the regulatory process as part of Oncor’s rates.
The following table summarizes the changes to the asset retirement liability, reported in other noncurrent liabilities and deferred credits in the balance sheet, during the years ended December 31, 2009 and 2008:
Oncor’s Regulatory Assets and Liabilities
Recognition of regulatory assets and liabilities and the amortization periods over which they are expected to be recovered or refunded through rate regulation reflect the decisions of the PUCT. Components of the regulatory assets and liabilities are provided in the table below. Amounts not earning a return through rate regulation are noted. On August 31, 2009, the PUCT issued a final order on Oncor’s rate review filed in June 2008. The rate review included a determination of the recoverability of regulatory assets as of December 31, 2007, including the recoverability period of those assets deemed allowable by the PUCT. The PUCT’s findings included denial of recovery of certain regulatory assets primarily related to business restructuring costs and rate case expenses, which resulted in a $25 million charge ($16 million after-tax) in the third quarter 2009 reported in other deductions in the Regulated Delivery segment.
(a) Not earning a return in the regulatory rate-setting process.
(b) Costs incurred since the period covered under the last rate review.
(c) Recovery is specifically authorized by statute, subject to reasonableness review by the PUCT.
(d) Represents unfunded liabilities recorded in accordance with pension and OPEB accounting standards.
(e) Offset by an intercompany payable to TCEH.
(f) Rate case expenses totaling $4 million were disallowed by the PUCT and written off in the third quarter of 2009.
(g) All previously recorded business restructuring costs were disallowed by the PUCT and written off in the third quarter of 2009.
As part of purchase accounting, the carrying value of the generation-related regulatory assets was reduced by $213 million, and this amount is being accreted to other income over the approximate nine-year recovery period remaining as of the date of the Merger.
In September 2008, the PUCT approved a settlement for Oncor to recover its estimated future investment for advanced metering deployment. Oncor began billing the advanced metering surcharge in the January 2009 billing month cycle. The surcharge is expected to total $1.023 billion over the 11-year recovery period and includes a cost recovery factor of $2.19 per month per residential retail customer and $2.39 to $5.15 per month for non-residential retail customers. We account for the difference between the surcharge billings for advanced metering facilities and the allowed revenues under the surcharge provisions, which are based on expenditures and an allowed return, as a regulatory asset or liability. Such differences arise principally as a result of timing of expenditures. As indicated in the table above, the regulatory liability at December 31, 2009 totaled $57 million.
See Note 6 for discussion of effects on regulatory assets and liabilities of the stipulation approved by the PUCT and Note 19 for additional information regarding nuclear decommissioning cost recovery.
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
Unfavorable Purchase and Sales Contracts - Unfavorable purchase and sales contracts primarily represent the extent to which contracts on a net basis were unfavorable to market prices as of the date of the Merger. These are contracts for which: (i) TCEH has made the “normal” purchase or sale election allowed or (ii) the contract did not meet the definition of a derivative under accounting standards related to derivative instruments and hedging transactions. Under purchase accounting, TCEH recorded the value as of October 10, 2007 as a deferred credit. Amortization of the deferred credit related to unfavorable contracts is primarily on a straight-line basis, which approximates the economic realization, and is recorded as revenues or a reduction of purchased power costs as appropriate. The amortization amount totaled $27 million and $30 million in 2009 and 2008, respectively, and $5 million in the 2007 Successor period. Favorable purchase and sales contracts are recorded as intangible assets (see Note 3).
The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:
Liabilities Related to Subsidiary Tax Sharing Agreement - Amount represents the previously recorded net deferred tax liabilities of Oncor related to the noncontrolling interests. Upon the sale of noncontrolling interests in Oncor (see Note 15), Oncor became a partnership for US federal income tax purposes, and the temporary differences which gave rise to the deferred taxes will, over time, become taxable to the noncontrolling interests. Under a tax sharing agreement among Oncor and its equity holders, Oncor reimburses the equity holders for federal income taxes as the partnership earnings become taxable to such holders. Accordingly, as the temporary differences become taxable, the equity holders will be reimbursed by Oncor. In the unlikely event such amounts are not reimbursed under the tax sharing agreement, it is probable they would be refunded to rate payers. The net changes in the liability for the year ended December 31, 2009 totaling $22 million reflected changes in temporary differences.
Supplemental Cash Flow Information
(a) Net of interest received on interest rate swaps.
(b) Multi-year power sales agreement entered into with Alcoa Inc. and recorded as part of the construction work-in-process asset balance for the Sandow 5 coal-fueled generation unit.
(c) Represents end-of-period accruals.
26. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION
In 2007, EFH Corp. issued $2.0 billion EFH Corp. 10.875% Notes and $2.5 billion EFH Corp. Toggle Notes (collectively, the EFH Corp. Senior Notes). In May 2009 and November 2009, EFH Corp. issued an additional $150 million and $159 million, respectively, of the EFH Corp. Toggle Notes. In November 2009, EFH Corp. issued $115 million EFH Corp. 9.75% Notes in exchange for certain outstanding debt securities (see Note 12). The EFH Corp. Senior Notes and 9.75% Notes are unconditionally guaranteed by EFC Holdings and Intermediate Holding, 100% owned subsidiaries of EFH Corp. (collectively, the Guarantors) on an unsecured basis except for the Intermediate Holding guarantee of the EFH Corp. 9.75% Notes, which is secured by a pledge of all membership interests and other investments Intermediate Holding owns or holds in Oncor Holdings or any of Oncor Holdings’ subsidiaries as described in Note 12. The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the EFH Corp. Senior Notes and 9.75% Notes. The guarantees by EFC Holdings and the guarantee of the EFH Corp. Senior Notes by Intermediate Holding rank equally with any senior unsecured indebtedness of the Guarantors and rank effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. All other subsidiaries of EFH Corp., either direct or indirect, do not guarantee the EFH Corp. Senior Notes and 9.75% Notes (collectively, the Non-Guarantors). The indentures governing the EFH Corp. Senior Notes and 9.75% Notes contain certain restrictions, subject to certain exceptions, on EFH Corp.’s ability to pay dividends or make investments. See Note 12.
The following tables have been prepared in accordance with Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered” in order to present the condensed consolidating statements of income and cash flows of EFH Corp. (the Parent/Issuer), the Guarantors and the Non-Guarantors for the years ended December 31, 2009 and 2008, the period from October 11, 2007 through December 31, 2007 and the period from January 1, 2007 through October 10, 2007 and the consolidating balance sheets as of December 31, 2009 and 2008 of the Parent/Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5-J, “Push Down Basis of Accounting Required in Certain Limited Circumstances”, including the effects of the push down of the $4.63 billion and $4.5 billion principal amount of EFH Corp. Senior Notes as of December 31, 2009 and 2008, respectively, and the $115 million principal amount of the EFH Corp. 9.75% Notes as of December 31, 2009 to the Guarantors (see Notes 12 and 13).
EFH Corp. (Parent) received dividends from its consolidated subsidiaries totaling $216 million, $329 million and $1.461 billion for the years ended December 31, 2009 and 2008 and the Predecessor period from January 1, 2007 through October 10, 2007, respectively. EFH Corp. also received a distribution of $1.253 billion indirectly from Oncor as discussed in Note 15. No dividends were received during the period from October 11, 2007 through December 31, 2007. See Note 14.
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Income
For the Year Ended December 31, 2009
(millions of dollars)
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Income
For the Year Ended December 31, 2008
(millions of dollars)
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Income
For the Period from October 11, 2007 through December 31, 2007
(millions of dollars)
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Income
For the Period from January 1, 2007 through October 10, 2007
(millions of dollars)
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2009
(millions of dollars)
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2008
(millions of dollars)
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
Period from October 11, 2007 through December 31, 2007
(millions of dollars)
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
Period from January 1, 2007 through October 10, 2007
(millions of dollars)
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Balance Sheets
at December 31, 2009
(millions of dollars)
ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Balance Sheets
at December 31, 2008
(millions of dollars)
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
Item 9A.
Item 9A. CONTROLS AND PROCEDURES
An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect as of December 31, 2009. Based on the evaluation performed, our management, including the principal executive officer and principal financial officer, concluded that the disclosure controls and procedures were effective.
There has been no change in our internal control over financial reporting during the most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ENERGY FUTURE HOLDINGS CORP.
MANAGEMENT’S ANNUAL REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Energy Future Holdings Corp. is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) for the company. Energy Future Holdings Corp.’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in condition or the deterioration of compliance with procedures or policies.
The management of Energy Future Holdings Corp. performed an evaluation as of December 31, 2009 of the effectiveness of the company’s internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission’s (COSO’s) Internal Control-Integrated Framework. Based on the review performed, management believes that as of December 31, 2009 Energy Future Holdings Corp.’s internal control over financial reporting was effective.
The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated financial statements of Energy Future Holdings Corp. has issued an attestation report on Energy Future Holdings Corp.’s internal control over financial reporting.
/s/ JOHN F. YOUNG
/s/ PAUL M. KEGLEVIC
John F. Young, President and
Paul M. Keglevic, Executive Vice President
Chief Executive Officer
and Chief Financial Officer
February 18, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Energy Future Holdings Corp.
Dallas, Texas
We have audited the internal control over financial reporting of Energy Future Holdings Corp. and subsidiaries (“EFH Corp.”) as of December 31, 2009 (successor) based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. EFH Corp.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on EFH Corp.’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of the changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, EFH Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of December 31, 2009 (successor) and for the year ended December 31, 2009 (successor) of EFH Corp. and our report dated February 18, 2010 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 18, 2010
Item 9B.
Item 9B. OTHER INFORMATION
On February 15, 2010, the Organization and Compensation Committee (O&C Committee) of the Board approved several changes to our Chief Executive Officer and President’s (John Young) compensation arrangements, including certain amendments to his employment agreement and his stock option agreement. Generally, these changes were made after considering relevant market compensation data and for retention purposes.
Pursuant to Mr. Young’s amended employment agreement, Mr. Young’s base salary was increased from $1,000,000 to $1,200,000, which increase will be effective retroactively to January 1, 2010, and Mr. Young was granted a new cash-based retention incentive award (Retention Award). Under the terms of the Retention Award, Mr. Young will be entitled to receive on September 30, 2012, to the extent Mr. Young remains employed by EFH Corp. on such date (with customary exceptions for death, disability and leaving for “good reason” or termination without “cause”), an additional one-time, lump-sum cash payment equal to 100% of the aggregate Executive Annual Incentive Plan award received by (or otherwise payable to) Mr. Young for fiscal years 2009, 2010 and 2011.
In addition, Mr. Young’s amended employment agreement provides that EFH Corp. will (i) purchase, on behalf of Mr. Young, a 10 year term life insurance policy in an insured amount equal to $10,000,000 and (ii) adopt a supplemental retirement plan for Mr. Young that vests on December 31, 2014 (with customary exceptions for death, disability and leaving for “good reason” or termination “without cause”) with a value of $3,000,000.
Pursuant to Mr. Young’s amended stock option agreement, Mr. Young received a grant of 3,000,000 new stock options under the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and Affiliates (Stock Option Plan) at a strike price of $3.50 per share. Half of Mr. Young’s new stock options are cliff-vested options that will vest 100% on September 30, 2014, and the other half are time-vested options that will vest 20% per year over a five-year period beginning September 30, 2009. In connection with the grant of these new stock options, Mr. Young surrendered to EFH Corp. 1,500,000 unvested performance-related stock options that were granted to Mr. Young when he joined EFH Corp.
Also, in February 2010, the O&C Committee increased James A. Burke’s (President and Chief Executive of TXU Energy) base salary to $630,000. The increase took effect retroactively on January 1, 2010.
PART III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Directors
The names of EFH Corp.’s directors and information about them, as furnished by the directors themselves, are set forth below:
Name
Age
Served As
Director
Since
Business Experience
Arcilia C. Acosta (1)(4)
Arcilia C. Acosta has served as a Director of EFH Corp. since May 2008. During the last five years, Ms. Acosta’s principal occupation and employment has been serving as the CEO of CARCON Industries & Construction, L.L.C. (CARCON) and its subsidiaries. She is also the CEO and controlling principal of Southwestern Testing Laboratories, L.L.C. (STL). CARCON’s principal business is commercial, institutional and transportation construction. STL’s principal business is geotechnical engineering, construction materials testing and environmental consulting. Ms. Acosta is a former Chair of the State of Texas Hispanic chambers organization known as the Texas Association of Mexican American Chambers of Commerce (TAMACC) and the Greater Dallas Hispanic Chamber of Commerce. Ms. Acosta serves on the Board of Advisors for Compass Bank and the Board of Governors for the Dallas Foundation.
David Bonderman
David Bonderman has served as a Director of EFH Corp. since October 2007. He is a founding partner of TPG Capital, L.P. (TPG). Before forming TPG in 1992, Mr. Bonderman was Chief Operating Officer of the Robert M. Bass Group (now doing business as Keystone Group L.P.) in Fort Worth, Texas. He serves on the boards of the following public companies: Armstrong World Industries, Inc., CoStar Group, Inc., Gemalto N.V., General Motors Company, Harrahs’s Entertainment, RyanAir Holdings PLC, for which he serves as Chairman of the Board, and Univision Communications, Inc. During the past five years, Mr. Bonderman also served on the boards of Burger King Holdings, Inc., Ducati Motor Holding S.P.A., Gemplus International S.A. (predecessor to Gemalto N.V.), IASIS Healthcare Corporation, Korea First Bank Ltd., Mobilcom AG, and Washington Mutual, Inc.
Donald L. Evans (2)(3)(4)
Donald L. Evans has served as a Director and Non-Executive Chairman of EFH Corp. since October 2007. He was CEO of the Financial Services Forum from 2005 to 2007, after serving as the 34th secretary of the US Department of Commerce. Before serving as Secretary of Commerce, Mr. Evans was the former CEO of Tom Brown, Inc., a large independent energy company. He also previously served as a member and chairman of the Board of Regents of the University of Texas System. Mr. Evans is also a Senior Partner at Quintana Energy Partners, L.P.
Name
Age
Served As
Director
Since
Business Experience
Thomas D. Ferguson (3)
Thomas D. Ferguson has served as a Director of EFH Corp. since December 2008. He is a Managing Director of Goldman, Sachs & Co., having joined the firm in 2003. Mr. Ferguson heads the asset management efforts for the merchant bank’s infrastructure investment activity worldwide. He currently serves on the boards of some of Goldman, Sachs & Co.’s largest infrastructure investments, including Associated British Ports, the largest port company in the UK; Carrix, one of the largest private container terminal operators in the world; and Red de Carreteras, a major toll road concessionaire in Mexico. Additional responsibilities at Goldman, Sachs & Co. include an 18 month stint as the CEO of National Golf/American Golf, one of the leading owner/operators of golf courses in the US for which he now serves as the company’s non-executive Chairman.
Frederick M. Goltz (2)(3)
Frederick M. Goltz has served as a Director of EFH Corp. since October 2007. He has been with Kohlberg Kravis Roberts and Co., L.P. (KKR) for 14 years. Mr. Goltz has played a significant role in the development of many of the themes pursued by KKR in the energy space, including those related to integrated utilities, merchant generation, and oil and gas exploration and production. He now heads KKR’s newly created Mezzanine Fund headquartered in San Francisco. He is a director of EFC Holdings, TCEH, and Luminant. During the past five years, Mr. Goltz also served on the boards of Accuride Corp. and Texas Genco Holdings, Inc.
James R. Huffines (1)(3)
James R. Huffines has served as a Director of EFH Corp. since October 2007. He is Chairman of the University of Texas System Board of Regents, after previously serving as Vice Chairman from November 2007 to April 2009 and Chairman from June 2004 to November 2007. He also is Chairman, Central and South Texas Region, of PlainsCapital Bank, Senior Executive Vice President of PlainsCapital Corporation, and a director of Andrew Harper Travel Publications, Inc. and PlainsCapital Bank.
Scott Lebovitz
Scott Lebovitz has served as a Director of EFH Corp. since October 2007. He is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area. He joined Goldman, Sachs & Co. in 1997 and was promoted to Managing Director in 2007. Mr. Lebovitz serves on the boards of both public and private companies, including CVR Energy, Inc., EFC Holdings, TCEH, and Luminant.
Jeffrey Liaw
Jeffrey Liaw has served as a Director of EFH Corp. since October 2007. He is active in TPG’s energy and industrial investing practice areas. Before joining TPG in 2005, he worked for Bain Capital in its industrials practice. Mr. Liaw serves on the boards of both public and private companies, including Graphic Packaging Holding Company and Oncor.
Marc S. Lipschultz (2)(4)
Marc S. Lipschultz has served as a Director of EFH Corp. since October 2007. He joined KKR in 1995 and is the global head of KKR’s Energy and Infrastructure business. Mr. Lipschultz serves on KKR’s Management Committee and its Infrastructure Investment Committee. Currently, he is on the boards of Accel-KKR Company and Oncor. During the past five years, Mr. Lipschultz also served on the boards of Texas Genco Holdings, Inc. and The Boyds Collection, Ltd.
Name
Age
Served As
Director
Since
Business Experience
Michael MacDougall (2)(3)
Michael MacDougall has served as a Director of EFH Corp. since October 2007. He is a partner of TPG. Prior to joining TPG in 2002, Mr. MacDougall was a vice president in the Principal Investment Area of the Merchant Banking Division of Goldman, Sachs & Co., where he focused on private equity and mezzanine investments. Mr. MacDougall serves on the board of directors of both public and private companies, including Graphic Packaging Holding Company, Kraton Performance Polymers Inc., Valerus Compression Services, L.P., EFC Holdings, TCEH, and Luminant. During the past five years, he also served on the board of Aleris International. Mr. MacDougall also serves as the Chairman of the Board of The Opportunity Network and is a member of the Board of the Dwight School Foundation and Islesboro Affordable Property.
Lyndon L. Olson, Jr. (3)
Lyndon L. Olson, Jr. has served as a Director of EFH Corp. since October 2007. He was a Senior Advisor with Citigroup Inc. from 2002 to 2008, after serving as United States Ambassador to Sweden from 1998 to 2001. He previously was affiliated with Citigroup from 1990 to 1998, as President and CEO of Travelers Insurance Holdings and the Associated Madison Companies, predecessor companies. Before joining Citigroup, he had been President of the National Group Corporation and CEO of its National Group Insurance Company. Ambassador Olson also is a former Chairman and a Member of the Texas 173 State Board of Insurance, former President of the National Association of Insurance Commissioners, and a former member of the Texas House of Representatives. Ambassador Olson also serves on the board of First Acceptance Corporation, Sammons Enterprises and Texas Meter and Device Company.
Kenneth Pontarelli (2)(4)
Kenneth Pontarelli has served as a Director of EFH Corp. since October 2007. He is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area. He transferred to the Principal Investment Area in 1999 and was promoted to Managing Director in 2004. Mr. Pontarelli serves as a director of both public and private companies, including CCS, Inc., Cobalt International Energy, L.P., Expro International Group Ltd., CVR Energy, Inc., Kinder Morgan, Inc. and TXU Energy.
William K. Reilly
William K. Reilly has served as a Director of EFH Corp. since October 2007. He is a Senior Advisor to TPG and a founding partner of Aqua International Partners, an investment group that invests in companies that serve the water and renewable energy sectors. Mr. Reilly previously served as the seventh Administrator of the EPA. Mr. Reilly is a director of the following public companies: E.I DuPont de Nemours and Company, Eden Springs, Ltd. of Israel, ConocoPhillips and Royal Caribbean International. During the past five years, he also served on the board of Ionics Inc. Before serving as EPA Administrator, Mr. Reilly was President of World Wildlife Fund and President of The Conservation Foundation. He previously served as Executive Director of the Rockefeller Task Force on Land Use and Urban Growth, a senior staff member of the President’s Council on Environmental Quality, and Associate Director of the Urban Policy Center and the National Urban Coalition. Mr. Reilly is Co-Chairman of the National Commission on Energy Policy.
Name
Age
Served As
Director
Since
Business Experience
Jonathan D. Smidt
Jonathan D. Smidt has served as a Director of EFH Corp. since October 2007. He has been with KKR since 2000, where he is a member of the firm’s Energy and Natural Resources industry team. Currently, he is a director of Laureate Education Inc., East Resources Inc. and TXU Energy.
John F. Young (2)(3)
John F. Young has served as a Director and President and Chief Executive of EFH Corp. since January 2008. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon from March 2003 to January 2008 including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation. Mr. Young is also a director of Luminant.
Kneeland Youngblood (1)
Kneeland Youngblood has served as a Director of EFH Corp. since October 2007. He is a founding partner of Pharos Capital Group, a private equity firm that focuses on providing growth and expansion capital to businesses in technology, business services, and health care services. Mr. Youngblood is a director of the following public companies: Starwood Hotels and Resorts Worldwide, Inc., Gap Inc. and Burger King Holdings, Inc. Mr. Youngblood is a member of the Council on Foreign Relations.
(1) Member of Audit Committee.
(2) Member of Executive Committee.
(3) Member of Governance and Public Affairs Committee
(4) Member of Organization and Compensation Committee
Director Qualifications
In October 2007, David Bonderman, Donald L. Evans, Frederick M. Goltz, James R. Huffines, Scott Lebovitz, Jeffrey Liaw, Marc S. Lipschultz, Michael MacDougall, Lyndon L. Olson, Jr., Kenneth Pontarelli, William K. Reilly, Jonathan D. Smidt, and Kneeland Youngblood were elected to EFH Corp.’s board of directors (the “Board”). Arcilia C. Acosta, Thomas D. Ferguson and John F. Young joined the Board in 2008. Messrs. Bonderman, Ferguson, Goltz, Lebovitz, Liaw, Lipschultz, MacDougall, Pontarelli, and Smidt are collectively referred to as the “Sponsor Directors.” Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly, Young, and Youngblood are collectively referred to as the “Non-Sponsor Directors.”
Each of the Sponsor Directors was elected to the Board pursuant to the Limited Partnership Agreement of Texas Energy Future Holdings Limited Partnership, the holder of a majority of the outstanding capital stock of the Company. Pursuant to such agreement, Messrs. Goltz, Lipschultz and Smidt were appointed to the Board as a consequence of their relationships with Kohlberg Kravis Roberts & Co.; Messrs. Bonderman, Liaw and MacDougall were appointed to the Board as a consequence of their relationships with TPG Capital, L.P., and Messrs. Ferguson, Lebovitz and Pontarelli were appointed to the Board as a consequence of their relationships with GS Capital Partners.
When considering whether the Board’s directors and nominees have the experience, qualifications, attributes and skills, taken as a whole, to enable the Board to satisfy its oversight responsibilities effectively in light of EFH Corp.’s business and structure, the Board focused primarily on the information in each of the Board member’s or nominee’s biographical information set forth on the pages above. In addition, EFH Corp. believes that each of its directors possesses high ethical standards, acts with integrity, and exercises careful judgment. Each is committed to employing his/her skills and abilities in the long-term interests of EFH Corp and its stakeholders. Finally, our directors are knowledgeable and experienced in business, governmental, and civic endeavors, further qualifying them for service as members of the Board.
The Sponsor Directors possess experience in owning and managing privately held enterprises and are familiar with corporate finance and strategic business planning activities of highly-leveraged companies such as EFH Corp. Some of the Sponsor Directors also have experience advising and overseeing the operations of large industrial, manufacturing or retail companies similar to our businesses. Finally, several of the Sponsor Directors possess substantial expertise in advising and managing companies in segments of energy industry, including, among others, power generation, oil and gas, and energy infrastructure and transportation.
As a group and individually, the Non-Sponsor Directors possess extensive experience in governmental and civic endeavors and in the business community, in each case, in the markets where our businesses operate.
Mr. Young’s employment agreement provides that he will serve as a member of the Board during the time he is employed by the Company. Before joining the Company as President and Chief Executive Officer, he held various senior management positions at other companies in the energy industry over twenty years, including, most recently, his role as Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation.
Ms. Acosta manages the operations of a large commercial construction company in Texas and has significant experience within the local Hispanic business community, having served as the chair of the Greater Dallas Hispanic Chamber of Commerce and the Texas Association of Mexican American Chambers of Commerce. Mr. Evans has demonstrated ability and achievement in both the private and public sectors, serving as U.S. Secretary of Commerce during the Bush Administration, and both before and after his government service, acting as Chairman and Chief Executive Officer of a publicly-owned energy company, Tom Brown, Inc. Mr. Huffines has demonstrated achievement in both business and academic endeavors, and, given his employment in various senior management positions in the banking industry, has sufficient experience and expertise in financial matters to qualify him to serve as EFH Corp.’s “audit committee financial expert.” Mr. Olson possesses substantial experience in both federal and state government through, among other things, his service as the former US Ambassador to Sweden and as a former member of the Texas House of Representatives, and has advised and overseen the operations of large companies, in particular his service in the insurance industry. Mr. Reilly possesses a distinguished record of public service and extensive policy-making experience as a former administrator of the EPA, lectures extensively on environmental issues facing companies operating in the energy industry and currently serves as Co-Chairman of the National Commission on Energy Policy. Mr. Youngblood has served on numerous boards for large public companies, has extensive experience managing and advising companies in his capacity as a partner in a private equity firm (not affiliated with the Sponsor Group), is highly knowledgeable of federal and state political matters, and has served on the board of directors of the United States Enrichment Corporation, a company that contracts with the US Department of Energy to produce enriched uranium for use in nuclear power plants.
Executive Officers
The names and information regarding EFH Corp.’s executive officers are set forth below:
Name of Officer
Age
Positions and Offices
Presently Held
Date First Elected
to Present Offices
Business Experience
(Preceding Five Years)
John F. Young
President and Chief
Executive Officer
of EFH Corp.
January 2008
John F. Young was elected President and Chief Executive Officer of EFH Corp. in January 2008. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon Corporation from March 2003 to January 2008, including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation.
James A. Burke
President and Chief
Executive of TXU
Energy
August 2005
James A. Burke was elected President and Chief Executive of TXU Energy in August 2005. Previously, Mr. Burke was Senior Vice President Consumer Markets of TXU Energy.
David A. Campbell
President and Chief Executive of Luminant
June 2008
David A. Campbell was elected President and Chief Executive of Luminant in June 2008. Mr. Campbell was Executive Vice President and Chief Financial Officer of EFH Corp. from April 2007 to June 2008 having previously served as Acting Chief Financial Officer beginning in March 2006 and as Executive Vice President for Corporate Planning, Strategy & Risk when he joined the company in May 2004.
Charles R. Enze
Executive Vice
President and Chief
Executive of
Luminant
Construction
September 2006
Charles R. Enze was elected Executive Vice President and Chief Executive of Luminant Construction in September 2006. Prior to joining EFH Corp. in 2006, Mr. Enze was Vice President of Engineering and Projects for Shell International Exploration & Production.
M. S. Greene
Vice Chairman of
EFH Corp.
June 2008
M. S. Greene was elected Vice Chairman of EFH Corp. in June 2008. Previously Mr. Greene held several other offices including President and Chief Executive of Luminant, Chairman of the Board, President and Chief Executive of TXU Power, Executive Vice President of TCEH, and Vice Chairman, Chief Executive and President of Oncor.
Joel D. Kaplan
Executive Vice
President of EFH Corp.
November 2009
Joel D. Kaplan was elected Executive Vice President of EFH Corp. in November 2009 and oversees the company’s public affairs organization. Prior to joining EFH Corp., Mr. Kaplan served as Deputy Chief of Staff in the George W. Bush White House from 2006 to 2008 and Deputy Director of the Office of Management and Budget from 2003 to 2006.
There is no family relationship between any of the above-named executive officers.
Audit Committee Financial Expert
The Board has determined that James R. Huffines is an “Audit Committee Financial Expert” as defined in Item 407(d)(5) of SEC Regulation S-K.
Code of Conduct
EFH Corp. maintains certain corporate governance documents on EFH Corp’s website at www.energyfutureholdings.com. EFH Corp.’s Code of Conduct can be accessed by selecting “Investor Relations” on the EFH Corp. website. EFH Corp.’s Code of Conduct applies to all of its employees, officers (including the Chief Executive Officer, Chief Financial Officer and Principal Accounting Officer) and directors. Any amendments to the Code of Conduct will be posted on EFH Corp.’s website. Printed copies of the corporate governance documents that are posted on EFH Corp.’s website are also available to any investor upon request to the Secretary of EFH Corp. at 1601 Bryan Street, Dallas, Texas 75201-3411.
Procedures for Shareholders to Nominate Directors; Arrangement to Serve as Directors
The Amended and Restated Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC, the general partner of Texas Holdings, generally requires that the members of Texas Energy Future Capital Holdings LLC take all necessary action to ensure that the persons who serve as its managers also serve on the EFH Corp. Board. In addition, Mr. Young’s employment agreement provides that he will continue to serve as a member of the Board during the time he is employed by EFH Corp.
Because of these requirements, together with Texas Holdings’ controlling ownership of EFH Corp.’s outstanding common stock, there is no policy or procedure with respect to shareholder recommendations for nominees to the EFH Corp. Board.
Item 11.
Item 11. EXECUTIVE COMPENSATION
Organization and Compensation Committee
The Organization and Compensation Committee (the “O&C Committee”) of EFH Corp.’s Board of Directors (the “Board”) is comprised of four non-employee directors: Arcilia C. Acosta, Donald L. Evans, Marc S. Lipschultz and Kenneth Pontarelli. The primary responsibility of the O&C Committee is to:
•
determine and oversee the compensation program of EFH Corp. and its subsidiaries (other than the Oncor Ring-Fenced Entities), including making recommendations to the Board with respect to the adoption, amendment or termination of compensation and benefits plans, arrangements, policies and practices;
•
evaluate the performance of EFH Corp.’s Chief Executive Officer (the “CEO”) and the other executive officers of EFH Corp. and its subsidiaries (other than the Oncor Ring-Fenced Entities) (collectively, the “executive officers”), including all of the executive officers named in the Summary Compensation Table (the “Named Executive Officers”), and
•
approve executive compensation based on those evaluations.
Compensation Discussion and Analysis
Compensation of the CEO
In determining the compensation of the CEO, the O&C Committee annually follows a thorough and detailed process. At the end of each year, the O&C Committee reviews a self-assessment prepared by the CEO regarding his performance and the performance of our businesses and meets (with and without the CEO) to evaluate and discuss his performance and the performance of our businesses.
In addition to conducting an annual review of the CEO’s performance, the O&C Committee periodically uses independent compensation consultants to assess the compensation of the CEO against a variety of market reference points and competitive data, including the compensation practices of a number of companies that we consider to comprise our peer group, size-adjusted energy services industry survey data and size-adjusted general industry survey data. While the O&C Committee tries to ensure that the bulk of the CEO’s compensation is directly linked to his performance and the performance of our businesses, the O&C Committee also seeks to set his compensation in the manner that is competitive for retention purposes. The last assessment of the CEO’s compensation was performed in late 2009 / early 2010, when the O&C Committee engaged Towers Watson to perform a competitive analysis of the CEO’s compensation. In January 2010, Towers Watson delivered its report to the O&C Committee, which report included market data for a peer group composed of the following companies:
AES Corporation
Allegheny Energy, Inc.
Ameren Corp.
American Electric Power Co. Inc,
Calpine Corp.
Constellation Energy Group Inc.
Dominion Resources Inc.
Duke Energy Corp.
Edison International
Entergy Corp.
Exelon Corp.
FirstEnergy Corp.
FPL Group Inc.
Mirant Corp.
NRG Energy, Inc.
PPL Corp.
Progress Energy Inc.
Public Service Enterprise Group Inc.
RRI Energy Inc.
Southern Co.
Xcel Energy Inc.
The data for CEO compensation of the peer group was developed at both the 50th and 75th percentiles of market in order to provide the O&C Committee with a broad market view and multiple benchmarks. The O&C Committee targets total direct compensation around the 75th percentile of the peer group.
While the O&C Committee considers market reference points and competitive data in determining the appropriate compensation of the CEO (and the other executive officers), the O&C Committee also considers qualitative and subjective factors that are more specific to EFH Corp. in making such determinations. One such factor is the fact that EFH Corp. is a highly-leveraged, privately-owned company. In this regard, while executive officers of publicly traded energy companies, including those in our peer group, are typically granted smaller long-term equity incentive awards on an annual basis, our executive officers received one-time, up front grants of long-term equity incentive awards intended to cover a multi-year period. Extended periods of economic strength or weakness generally has less affect on the cumulative value of annual awards as compared to one-time, up front awards because the annual awards are typically granted at fair market value over time. Accordingly, one-time, up front awards are typically riskier than annual awards.
After a comprehensive review of the CEO’s performance and the performance of our businesses in 2009, and taking into consideration the Towers Watson report, the economic dislocation occurring over the last 18 months and other qualitative and subjective factors as described above, the O&C Committee approved several changes to the compensation arrangement for the CEO in February 2010. The O&C Committee made these changes to provide incentives for retention and performance and to maintain a strong alignment between the CEO and our shareholders. We believe these changes are consistent with our compensation philosophy as described below.
Compensation of Other Executive Officers
In determining whether to make any adjustments to the compensation of any of our executive officers (other than the CEO), the O&C Committee seeks the input of the CEO. At the end of each year, the CEO reviews a self-assessment prepared by each of these executive officers and assesses the executive officer’s performance against business unit and individual goals and objectives. The O&C Committee and the CEO then review the CEO’s assessments and, in that context, the O&C Committee approves any adjustments to the compensation for each of these executive officers.
In addition to these annual reviews/assessments, the CEO periodically assesses the compensation of each of these executive officers. The last assessment of the compensation of the executive officers by the CEO was performed in the second half of 2009. Following that assessment, and taking into consideration the economic dislocation occurring over the last 18 months and other qualitative and subjective factors as described above, the CEO suggested several changes to the compensation arrangements for certain of our executive officers in order to provide incentives for retention and performance and to maintain alignment between our executive officers and shareholders. These changes, which are described in more detail below, were approved by the O&C Committee in October 2009 with respect to such executive officers, including each of Messrs. Keglevic, Campbell, Walters and Burke. We believe these changes are consistent with our compensation philosophy as described below.
Compensation Philosophy
We have a pay-for-performance compensation philosophy, which places an emphasis on pay-at-risk. In other words, a significant portion of an executive officer’s compensation is comprised of variable, at-risk incentive compensation. Our compensation program is intended to compensate executive officers appropriately for their contribution to the attainment of our financial, operational and strategic objectives. In addition, we believe it is important to retain our executive officers and strongly align their interests with EFH Corp.’s shareholders by emphasizing long-term incentive compensation, including equity-based compensation.
To achieve our compensation philosophy, we believe that:
•
compensation plans should balance both long-term and short-term objectives;
•
the overall compensation program should emphasize variable compensation elements that have a direct link to overall corporate performance and shareholder value, and
•
an executive officer’s individual compensation level should be based upon an evaluation of the financial and operational performance of that executive officer’s business unit as well as the executive officer’s individual performance.
We believe our compensation philosophy supports our businesses by:
•
aligning performance measures with our business objectives to drive the financial and operational performance of EFH Corp. and its business units;
•
rewarding business unit and individual performance by providing compensation levels consistent with the level of contribution and degree of accountability;
•
attracting and retaining the best performers, and
•
strengthening the correlation between the long-term interests of our executive officers and shareholders.
Elements of Compensation
The material elements of our executive compensation program are:
•
a base salary;
•
the opportunity to earn an annual performance-based cash bonus based on the achievement of specific corporate, business unit and individual performance goals, and
•
long-term incentive awards, primarily in the form of (i) long-term cash incentive awards and (ii) options to purchase shares of EFH Corp.’s common stock (the “Stock Option Awards”) under our 2007 Stock Incentive Plan for Key Employees of EFH Corp. and Affiliates (the “2007 Stock Incentive Plan”).
In addition, executive officers generally have the opportunity to participate in certain of our broad-based employee compensation plans, including our Thrift (401(k)) Plan, retirement plans and non-qualified benefit plans, and to receive certain perquisites.
Assessment of Compensation Elements
We design the majority of an executive officer’s compensation to be directly linked to corporate and business unit performance. For example, an executive officer’s annual performance-based cash bonus is primarily based on the achievement of certain corporate and business unit financial and operational targets (such as management EBITDA, cost management, generation output and customer satisfaction). In addition, the vesting of a portion of each executive officer’s Stock Option Awards is contingent upon the attainment of certain management EBITDA targets. We also try to ensure that our executive compensation program is competitive in order to reduce the risk of losing our executive officers.
The following is a detailed discussion of the principal compensation elements provided to our executive officers. More detail about each of the elements can be found in the compensation tables, including the footnotes to the tables, and the narrative discussion following certain of the tables.
Base Salary
Base salary should reward executive officers for the scope and complexity of their position and the level of responsibility required. We believe that a competitive level of base salary is required to attract and retain qualified talent.
The O&C Committee annually reviews base salaries and periodically uses independent compensation consultants to ensure the base salaries are market-competitive. The O&C Committee may also review an executive officer’s base salary from time to time during a year, including if the executive officer is given a promotion or if his responsibilities are significantly increased.
We want to ensure our cash compensation is competitive and sufficient to incent executive officers to remain with us, recognizing our high performance expectations across a broad set of operational, financial, customer service and community-oriented goals and objectives and the higher risk levels associated with being a significantly-leveraged company.
In light of the significant market dislocation and uncertainty that began in late 2008 and continued into 2009, our Named Executive Officers’ base salaries for 2009 remained unchanged from 2008 levels. In October 2009, the O&C Committee approved an increase in the base salary, effective January 1, 2010, for each of the Named Executive Officers, with the exception of Messrs. Young and Burke. In February 2010, the O&C Committee approved an increase in the base salary of each of Messrs. Young and Burke, which increases took effect retroactively on January 1, 2010. These increases reflect, in part, that none of the Named Executive Officers received a salary increase for 2009. The following table indicates the Named Executive Officers’ base salaries for 2008, 2009 and 2010.
(1) Mr. Chand’s employment with EFH Corp. terminated in October 2009.
Annual Performance-Based Cash Bonus - Executive Annual Incentive Plan
The Executive Annual Incentive Plan (“EAIP”) provides an annual performance-based cash bonus for the successful attainment of certain annual financial and operational performance targets that are established annually at each of the corporate and business unit levels by the O&C Committee. Under the terms of the EAIP, performance against these targets, which are generally set at challenging levels to incent high performance, drives bonus funding. Based on the level of attainment of these performance targets, an aggregate EAIP funding percentage amount for all participants is determined.
Our financial performance targets typically include “management” EBITDA, a non-GAAP financial measure. When the O&C Committee reviews management EBITDA for purposes of determining our performance against the applicable management EBITDA target, it includes our earnings before interest, taxes, depreciation and amortization plus transaction, management and/or similar fees paid to the Sponsor Group, together with such adjustments as the O&C Committee shall determine appropriate in its discretion after good faith consultation with the CEO and the Chief Financial Officer, including adjustments consistent with those included in the comparable definitions in TCEH’s Senior Secured Facilities (to the extent considered appropriate for executive compensation purposes). Our management EBITDA targets are also expected to be adjusted for acquisitions, divestitures or major capital investment initiatives to the extent that they were not contemplated in our financial plan (the “Financial Plan”). The management EBITDA targets are intended to measure achievement of the Financial Plan and the adjustments to management EBITDA described above primarily represent elements of our performance that are either beyond the control of management or were not predictable at the time the Financial Plan was submitted. The O&C Committee has broad authority to make these or any other adjustments to EBITDA that it deems appropriate in connection with its evaluation and compensation of our executive officers. Management EBITDA is an internal measure used only for performance management purposes, and EFH Corp. does not intend for management EBITDA to be an alternative to any measure of financial performance presented in accordance with GAAP. Management EBITDA is not the same as Adjusted EBITDA, which is disclosed elsewhere in this Form 10-K and defined in the glossary to this Form 10-K.
Financial and Operational Performance Targets
The following table provides a summary of the performance targets for Mr. Young, who had primary responsibility at EFH Corp.
(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.
The following table provides a summary of the performance targets for Messrs. Keglevic and Walters, who had primary responsibility at EFH Corp. and EFH Business Services.
(2) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.
The following table provides a summary of the performance targets for Mr. Campbell, who had primary responsibility at Luminant.
(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.
The following table provides a summary of the performance targets for Mr. Burke, who had primary responsibility at TXU Energy.
(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.
Individual Performance Modifier
After approving the actual performance against the applicable targets under the plan, the O&C Committee and/or the CEO reviews the performance of each of our executive officers on an individual and comparative basis. Based on this review, which includes an analysis of both objective and subjective criteria, including the CEO’s recommendations (with respect to all executive officers other than himself), the O&C Committee approves an individual modifier for each executive officer. Under the terms of the EAIP for 2009, the individual performance modifier can range from an outstanding rating (200%) to an unacceptable rating (0%). In February 2010, the O&C Committee amended the EAIP to reduce the maximum individual performance modifier applicable for 2010 and beyond from 200% to 150%. To calculate an executive officer’s final performance-based cash bonus, the executive officer’s corporate/business unit payout percentages are multiplied by the executive officer’s target incentive level, which is computed as a percentage of annualized base salary, and then by the executive officer’s individual performance modifier.
Actual Award
The following table provides a summary of the 2009 performance-based cash bonus for each Named Executive Officer (other than Mr. Chand) under the EAIP.
(1) Mr. Young’s incentive award is based on the successful achievement of the financial performance targets for EFH Corp. and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier that increased his incentive award. In 2009, Mr. Young successfully led the company in a difficult year in which sales volumes and demand fell, wholesale power prices declined and the credit markets were at times inaccessible. Notwithstanding these difficulties, Mr. Young created value in many parts of the company’s businesses. In particular, Mr. Young led the company’s efforts in, among other things: improving operations and safety at our generation and mining operations; participating in the national debate on climate change, green energy and financial reforms; bringing online two new lignite-fueled generation units on time and budget; implementing substantial and lasting cost reductions; exceeding EFH Corp.’s planned EBITDA for 2009; and strengthening the company’s management team. Given these and other significant achievements, the O&C Committee approved an individual performance modifier that increased Mr. Young’s incentive award.
(2) Mr. Keglevic’s incentive award is based on the successful achievement of the financial performance targets for EFH Corp. and EFH Business Services and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier that increased his incentive award. In 2009, Mr. Keglevic successfully implemented several new financial processes at EFH Corp. and its business units, including processes for understanding, managing and communicating the financial and operational performance of our businesses, managing the varied risks of our businesses and preserving effective liquidity levels. In addition, Mr. Keglevic led the company’s liquidity and liability management efforts, including the successful amendment to the TCEH Senior Secured Facilities. Given these significant accomplishments and other achievements (including his installation of a “drive for results” culture), the O&C Committee approved an individual performance modifier that increased Mr. Keglevic’s incentive award.
(3) Mr. Campbell’s incentive award is based on the successful achievement of a financial performance target for EFH Corp. and the financial and operational performance targets for Luminant and an individual performance modifier that increased his incentive award. In 2009, Mr. Campbell strengthened the Luminant management team (including, among others, the designation of a new Chief Nuclear Officer and Chief Fossil Officer) while overseeing strong financial and operational results primarily at Luminant’s nuclear plant and in Luminant’s wholesale energy organization. Luminant’s baseload generation construction program also achieved several important milestones, including the substantial completion of the two new lignite-fueled units, at costs and time-to-build schedules that are in the top decile relative to recent industry benchmarks. In addition, under Mr. Campbell’s leadership, Luminant had a very strong year for safety, with substantially all of its recordable safety metrics being in the top quartile for its industry. Given these significant accomplishments and other achievements (including his focus on developing strategic business solutions and building a team-oriented culture), the O&C Committee approved an individual performance modifier that increased Mr. Campbell’s incentive award.
(4) Mr. Walters’ incentive award is based on the successful achievement of the financial performance targets for EFH Corp. and EFH Business Services and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier that increased his incentive award. In 2009, Mr. Walters successfully managed several significant legal issues of the company. In particular, Mr. Walters’ led the company’s efforts in (i) defending the challenges to the Oak Grove and Sandow 5 construction and operating permits, (ii) negotiating the termination and transition of the company’s outsourcing relationship with CapGemini Energy and (iii) settling a dispute with the PUCT regarding alleged market manipulation activities. In addition, Mr. Walters drove improvements in the financial performance of our real estate holdings. Given these significant accomplishments and other achievements (including his strategic contributions in the political and civic arena on a local, state and national level), the O&C Committee approved an individual performance modifier that increased Mr. Walters’ incentive award.
(5) Mr. Burke’s incentive award is based on the successful achievement of a financial performance target for EFH Corp. and the financial and operational performance targets for TXU Energy and an individual performance modifier that increased his incentive award. In 2009, Mr. Burke strengthened the TXU Energy management team and performance-oriented culture to drive strong financial and operational results at TXU Energy. Among the operational results, Mr. Burke led the successful implementation of a new customer care system and successfully managed the transition of a number of functions previously performed by Capgemini Energy. Among the financial results, Mr. Burke was successful in driving improvement in retail margins, managing TXU Energy through a challenging economic environment and implementing overall customer satisfaction ratings. Given these significant accomplishments and other achievements (including his continued commitment to build a strong retail and customer-focused culture at TXU Energy), the O&C Committee approved an individual performance modifier that increased Mr. Burke’s incentive award.
In October 2009, the O&C Committee approved an increase in the annual target award under the EAIP from 75% of base salary to 85% of base salary for Messrs. Keglevic, Campbell, Walters and Burke. These increases will be effective for the 2010 award period.
Long-Term Incentive Awards
Long-Term Cash Incentive
In October 2009, the O&C Committee approved the adoption of a new long-term cash incentive (the “LTI”), effective as of the date of adoption, to be included by amendment in the employment agreements of each of Messrs. Keglevic, Campbell, Walters and Burke. Under the terms of the LTI, each of Messrs. Keglevic, Campbell, Walters and Burke will be entitled to receive on September 30, 2012, to the extent such Named Executive Officer remains employed by EFH Corp. on such date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”), an additional one-time, lump-sum cash payment equal to 75% of the aggregate EAIP award received by such executive officer for fiscal years 2009, 2010 and 2011.
In February 2010, the O&C Committee approved the adoption of an LTI to be included by amendment in the employment agreement of Mr. Young. Under the terms of the LTI, Mr. Young will be entitled to receive on September 30, 2012, to the extent Mr. Young remains employed by EFH Corp. on such date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”), an additional one-time, lump-sum cash payment equal to 100% of the aggregate EAIP award received by Mr. Young for fiscal years 2009, 2010 and 2011.
These awards provide significant retentive value because an award is not paid to an executive officer unless the executive officer remains employed with us until September 30, 2012 (subject to the customary exceptions described above). In addition, these awards provide additional incentive to our executive officers to achieve top operational and financial performance because the award is based on a percentage of the executive officers’ annual performance-based cash bonuses.
Long-Term Equity Incentives
We believe it is important to strongly align the interests of our executive officers and shareholders through equity-based compensation. In December 2007, our Board approved and adopted our 2007 Stock Incentive Plan pursuant to which we grant Stock Option Awards to our executive officers. The purpose of the 2007 Stock Incentive Plan is to:
•
promote our long-term financial interests and growth by attracting and retaining management and other personnel with the training, experience and ability to make a substantial contribution to our success;
•
motivate management and other personnel by means of growth-related incentives to achieve long-range goals, and
•
strengthen the correlation between the long-term interests of our shareholders and the interests of our executive officers through opportunities for stock (or stock-based) ownership in EFH Corp.
The Stock Option Awards granted to our executive officers provide significant retentive value because a portion of these awards is time-based and vest over a five year period. In addition, we believe that the Stock Option Awards granted to our executive officers provide incentive to our executive officers to achieve top operational and financial performance because a portion of these Stock Option Awards is performance-based and only vests upon EFH Corp. achieving certain management EBITDA targets.
In February 2008, Mr. Young was granted 7,500,000 Stock Option Awards. In May 2008, Messrs. Campbell, Walters and Burke were granted 4,000,000, 2,000,000 and 2,450,000 Stock Option Awards, respectively. In December 2008, Mr. Keglevic was granted 2,500,000 Stock Option Awards. Each of these Stock Option Awards are set forth in the table below and are referred to as the “Original Stock Option Awards,” half of which were “Original Time Vested Options” and half of which were “Original Performance Vested Options”. The exercise price of the Original Stock Option Awards (the fair market value on the grant date) is $5.00.
In October 2009 (February 2010, with respect to Mr. Young), the O&C Committee approved the grant of new Stock Option Awards to the Named Executive Officers as set forth in the table below. The new Stock Option Awards are referred to as the “New Stock Option Awards,” a portion of which are “New Time Vested Options” and a portion of which are “New Cliff Vested Options.” In connection with these grants, each Named Executive Officer surrendered to EFH Corp. a portion of his Original Performance Vested Options. The exercise price of the New Stock Option Awards is $3.50.
Please refer to the outstanding Equity Awards at Fiscal Year-End-2009 table, including the footnotes thereto, for a summary of the outstanding Stock Option Awards held by each of the Named Executive Officers.
The Stock Option Awards vest (subject to the executive officer continuing to be employed by EFH Corp.) as follows:
•
Time Vested Options
•
The Original Time Vested Options and the New Time Vested Options vest in 20% increments on each of the first five anniversaries of September 30, 2007 and September 30, 2009, respectively.
•
The New Cliff Vested Options vest 100% on September 30, 2014.
•
Performance Vested Options
•
The Original Performance Vested Options vest in 20% increments on each of the first five anniversaries of December 31, 2007, subject to our achievement of the annual management EBITDA target for the given fiscal year (or certain cumulative performance targets) as detailed in the stock option agreements.
In deciding whether to vest the Original Performance Vested Options, the O&C Committee considers EFH Corp.’s quantitative performance against certain management EBITDA targets. The method of calculating management EBITDA for purposes of vesting the Original Performance Vested Options is the same as the method for calculating management EBITDA for purposes of the EAIP, as described above. The O&C Committee also has broad discretion to consider other qualitative and quantitative criteria that it deems appropriate in connection with its decision to vest the Original Performance Vested Options.
Our management EBITDA for 2009 was less than the management EBITDA target of $5.569 billion set forth in the applicable stock option agreements with respect to 2009. While EFH Corp. did not meet the applicable management EBITDA target, which was originally established in 2007, it exceeded the management EBITDA target established by the O&C Committee in the beginning of 2009 for purposes of the EAIP. In addition, EFH Corp.’s actual SG&A for 2009 was less than the targeted amount of SG&A set by the O&C Committee. Given these achievements, as well as the successful attainment of most of the other annual financial and operational performance targets that were established by the O&C Committee at the beginning of 2009, the O&C Committee exercised its discretionary authority under the 2007 Stock Incentive Plan and approved the vesting of the 2009 Original Performance Vested Options.
In the future, we may make additional discretionary grants of stock options or other equity-based compensation to reward high performance or achievement.
Equity Investment
In addition to being granted Stock Option Awards, several of our Named Executive Officers (including Messrs. Young, Keglevic, Campbell and Burke) have an equity investment in EFH Corp. These investments have been made through a direct cash investment for shares of EFH Corp. common stock (Mr. Young) and/or through the receipt of restricted stock units (Mr. Young) or deferred shares of EFH Corp. common stock (Messrs. Keglevic, Campbell and Burke) (i) as a result of the executive officer foregoing the right to receive certain payments from EFH Corp., whether in respect of outstanding equity awards issued prior to the Merger or otherwise (Messrs. Campbell and Burke) or (ii) as consideration for compensation forfeited by the executive officer when he left his former employer to join EFH Corp. (Messrs. Young and Keglevic). We believe such investment strongly aligns the interests of our Named Executive Officers with the interests of our shareholders and provides increased incentive to our executive officers to maximize financial and operational performance because the value of their investment is dependant upon the success of EFH Corp. In addition, as we are a private company, the illiquid nature of the investment provides additional retentive value.
Other Elements of Compensation
General
Our executive officers generally have the opportunity to participate in certain of our broad-based employee compensation plans, including our Thrift (401(k)) Plan, retirement plans and non-qualified benefit plans. Please refer to the footnotes to the Summary Compensation table for a more detailed description of our Thrift Plan, the narrative that follows the Pension Benefits table for a more detailed description of our Retirement Plan and Supplemental Executive Retirement Plan and the footnotes to the Nonqualified Deferred Compensation table for a more detailed description of our Salary Deferral Program.
Perquisites
We do not believe that a significant amount of perquisites fit within our compensation philosophy. Those perquisites that exist are intended to serve as part of a competitive total compensation program and to enhance our executive officers’ ability to conduct company business. These benefits include financial planning, a preventive physical health exam and reimbursement for certain spousal travel expenses. Expenditures for the perquisites outlined above are disclosed by individual in footnotes to the Summary Compensation Table.
The following is a summary of perquisites offered to our Named Executive Officers that are not available to all employees:
Executive Financial Planning: We pay for our executive officers to receive financial planning services. This service is intended to support them in managing their financial affairs, which we consider especially important given the high level of time commitment and performance expectation required of our executive officers. Furthermore, we believe that such service helps ensure greater accuracy and compliance with individual tax regulations by our executive officers.
Annual Executive Physical Health Exam: We pay for our executive officers to receive annual physical health exams. The health of our executive officers is important given the vital leadership role they play in directing and operating the company. Our executive officers are important assets of EFH Corp., and this benefit is designed to help ensure their health and long-term ability to serve our shareholders.
Spouse Travel Expenses: From time to time, we pay for an executive officer’s spouse to travel with the executive officer when taking a business trip.
Contingent Payments
We have entered into employment agreements with Messrs. Young, Keglevic, Campbell, Walters and Burke. Each of the employment agreements provides that certain payments and benefits will be paid upon the expiration or termination of the agreement under various circumstances, including termination without cause, resignation for good reason and termination of employment within a fixed period of time following a change in control. We believe these provisions are important in order to attract and retain the caliber of executive officers that our business requires and provide incentive for our executive officers to fully consider potential changes that are in our and our shareholders’ best interest, even if such changes would result in the executive officers’ termination of employment. For a description of the applicable provisions in the employment agreements of our Named Executive Officers see “Potential Payments upon Termination or Change in Control.”
Other
In February 2010, the O&C Committee approved certain other compensation arrangements for Mr. Young. For a discussion of these arrangements, please see Item 9B, entitled Other Information in this Form 10-K.
Accounting and Tax Considerations
Accounting Considerations
Under FASB ASC Topic 718, the total amount of compensation expense to be recorded for stock-based awards (e.g., Stock Option Awards granted under the 2007 Stock Incentive Plan) is based on the fair value of the award on the grant date. This fair value is then recorded as expense over the vesting period, with an offsetting increase in paid-in capital. The amount of compensation expense is not subsequently adjusted for changes in our share price, for the actual number of shares distributed, or for any other factors except for true-ups related to estimated forfeitures compared to actual forfeitures. The surrendered shares are considered modifications to the original awards and are treated as an exchange of the original award for a new award. The compensation expense related to the new award represents the incremental costs of the surrendered shares and is based on the new grant date fair value and is recognized over its new vesting period.
Income Tax Considerations
Section 162(m) of the Code limits the tax deductibility by a publicly held company of compensation in excess of $1 million paid to the CEO or any other of its three most highly compensated executive officers other than the principal financial officer. Because EFH Corp. is a privately-held company, Section 162(m) will not limit the tax deductibility of any executive compensation for 2009.
The O&C Committee administers our compensation programs with the good faith intention of complying with Section 409A of the Code.
Organization and Compensation Committee Report
The O&C Committee has reviewed and discussed with management the Compensation Discussion and Analysis set forth in this Form 10-K. Based on this review and discussions, the committee recommended to the Board that the Compensation Discussion and Analysis be included in this Form 10-K.
Organization and Compensation Committee
Donald L. Evans, Chair
Arcilia C. Acosta
Marc S. Lipschultz
Kenneth Pontarelli
Summary Compensation Table
The following table provides information for the fiscal years ended December 31, 2009, 2008 and 2007 regarding the aggregate compensation paid to our Named Executive Officers.
(1) Mr. Young commenced employment with EFH Corp. in January 2008. The amounts for 2009 reported as “All Other Compensation” for Mr. Young represent (i) the costs of providing certain perquisites, including $9,728 for financial planning and $863 of taxable reimbursements partially related to his spouse’s travel and (ii) $14,700 and $80,000 for our matching contributions to the EFH Thrift Plan and the Salary Deferral Plan, respectively.
(2) Mr. Keglevic commenced employment with EFH Corp. in July 2008. Mr. Keglevic’s employment agreement provides that we pay him a signing bonus equal to $550,000 as follows: (i) $250,000 payable in July 2008; (ii) $150,000 payable in July 2009 and (iii) $50,000 payable in July 2010, 2011 and 2012. The amount for 2009 reported as “Bonus” for Mr. Keglevic represents the 2009 portion of his signing bonus. The amounts for 2009 reported as “All Other Compensation” for Mr. Keglevic represent (i) the costs of providing certain perquisites, including $2,724 for an executive physical, $3,410 of taxable reimbursements primarily related to his spouse’s travel and $11,836 for moving expenses and (ii) $7,350 and $48,000 for our matching contributions to the EFH Thrift Plan and the Salary Deferral Plan, respectively.
(3) The amount reported as “All Other Compensation” in 2009 for Mr. Campbell represents (i) $10,120 for financial planning and (ii) $4,900 for our matching contributions to the EFH Thrift Plan. The amount reported as “All Other Compensation” in 2008 for Mr. Campbell includes $3,319,963 for a tax gross-up payment that was made in 2009. The tax gross-up payment, which was not reported in the 2008 Summary Compensation Table, related to excise taxes due with respect to a January 2009 payment of $5,092,250 that was provided to Mr. Campbell as an inducement for entering into his employment agreement in 2008. The $5,092,250 was reported in the 2008 Summary Compensation Table under “Bonus,” and we believe the tax gross-up payment should be reported for the same calendar year as the related payment.
(4) Mr. Walters commenced employment with EFH Corp. in March 2008. The amounts for 2009 reported as “All Other Compensation” for Mr. Walters represent (i) the costs of providing certain perquisites, including $16,800 for financial planning, $2,350 for an executive physical and $1,712 of taxable reimbursements primarily related to his spouse’s travel and (ii) $14,700 and $46,000 for our matching contributions to the EFH Thrift Plan and the Salary Deferral Plan, respectively.
(5) The amounts for 2009 reported as “All Other Compensation” for Mr. Burke represent (i) the costs of providing certain perquisites, including $8,875 for financial planning, $2,350 for an executive physical and $660 of taxable reimbursements and (ii) $12,000 for our matching contributions to the EFH Thrift Plan.
(6) Mr. Chand’s employment terminated with EFH Corp. in October 2009. The amounts for 2009 reported as “All Other Compensation” for Mr. Chand represent (i) the costs of providing certain perquisites, including $8,875 for financial planning and $2,350 for an executive physical (ii) $14,700 for our matching contributions to the EFH Thrift Plan, (iii) $1,485,000 in cash severance due to him under the terms of his employment agreement, and (iv) $600,000 related to his deferred share agreement with EFH Corp.
(7) The amounts reported as “Option Awards” represent the grant date fair value of Stock Option Awards granted in the fiscal year computed for the stock options awarded under the 2007 Stock Incentive Plan in accordance with FASB ASC Topic 718 and do not take into account estimated forfeitures. See table titled “Grants of Plan-Based Awards - 2009”. In February 2010, Mr. Young received certain new Stock Option Awards. The grant date fair value of those Stock Option Awards was $3,405,000.
(8) The amounts in 2009 reported as “Non-Equity Incentive Plan Compensation” were earned by the executive officers in 2009 under the EAIP and are expected to be paid in March 2010.
(9) The amounts in 2009 reported under “Change in Pension Value and Nonqualified Deferred Compensation Earnings” (i) include the aggregate increase in actuarial value of EFH Corp.’s Retirement Plan and Supplemental Retirement Plan and (ii) exclude amounts attributable to the portion of the vested amounts for Messrs. Young ($33,313), Keglevic ($44,409), Walters ($62,351) and Burke ($19,500) that were transferred from the Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan as of December 31, 2009. For a more detailed description of EFH Corp.’s retirement plans, including the transfers of certain assets and liabilities from the Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan, please refer to the narrative that follows the table titled “Pension Benefits”. There are no above market earnings for nonqualified deferred compensation that is deferred under the Salary Deferral Program.
(10) As described above, “All Other Compensation” includes amounts associated with our matching contributions to the EFH Thrift Plan and Salary Deferral Plan. Our Thrift Plan allows participating employees to contribute a portion of their regular salary or wages to the plan. Under the Thrift Plan, EFH Corp. matches a portion of an employee’s contributions. This matching contribution is 100% of each Named Executive Officer’s contribution up to 6% of the named Executive Officer’s salary. All matching contributions are invested in Thrift Plan investments as directed by the participant. Please refer to the narrative that follows the Nonqualified Deferred Compensation table for a more detailed description of the Salary Deferral Program.
Grants of Plan-Based Awards - 2009
The following table sets forth information regarding grants of compensatory awards to our Named Executive Officers during the fiscal year ended December 31, 2009.
(1) The amounts disclosed under the heading “Estimated Possible Payouts under Non-Equity Incentive Plan Awards” reflect the threshold, target and maximum amounts available under the EAIP for each executive officer and each executive officer’s employment agreement. The actual awards for the 2009 plan year are expected to be paid in March 2010 and are reported in the Summary Compensation Table under the heading “Non-Equity Incentive Plan Compensation” and described above under the section entitled “Annual Performance Bonus - EAIP”.
(2) Represents grants of New Time Vested Options and New Cliff Vested Options under the 2007 Stock Incentive Plan, as described above under “Long-Term Incentive Awards.”
(3) The amounts reported under “Grant Date Fair Value of Stock Award” represent the grant date fair value of stock options related to the 2009 Awards in accordance with FASB ASC Topic 718.
For a discussion of the terms of the New Stock Option Awards granted to each Named Executive Officer (other than Mr. Chand) in connection with such Named Executive Officer surrendering a portion of his Original Performance Vested Options, please see “Long-Term Incentive Awards - Long-Term Equity Incentives.” For a discussion of certain material terms of the employment agreements with the Named Executive Officers, please see “Assessment of Compensation Elements” and “Potential Payments upon Termination or Change in Control.”
Outstanding Equity Awards at Fiscal Year-End- 2009
(1) These Original Time Vested Options are scheduled to become exercisable ratably in September 2010, 2011 and 2012 provided the Named Executive Officer has remained continuously employed by EFH Corp. through the applicable vesting date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”).
(2) These New Time Vested Options are scheduled to become exercisable ratably in September 2010, 2011, 2012, 2013 and 2014 provided the Named Executive Officer has remained continuously employed by EFH Corp. through the applicable vesting date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”).
(3) These New Cliff Vested Options are scheduled to become exercisable in September 2014 provided the Named Executive Officer has remained continuously employed by EFH Corp. through that date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”).
(4) If we achieve certain performance targets, these Original Performance Vested Options are eligible to become exercisable as of the end of fiscal years 2010, 2011 and 2012. See “Long-Term Incentive Awards-Long-Term Equity Incentives” for a detailed description of the vesting schedule for the Original Performance Vested Options and the decision by the O&C Committee in February 2010 to approve the vesting of a portion of the Original Performance Vested Options.
(5) This column reflects deferred shares described above under “Long-Term Incentive Awards-Equity Investment.” The deferred shares for Mr. Keglevic will vest and become nonforfeitable as to (i) 112,500 of the shares on the third anniversary of his employment (July 2011) and (ii) 112,500 of the shares on the fifth anniversary of his employment (July 2013).
(6) In February 2010, Mr. Young surrendered 1,500,000 Original Performance Vested Options listed in the “Equity Incentive Plan Awards: # of Securities Underlying Unexercised Unearned Options” column, and in connection therewith received 1,500,000 New Time Vested options and 1,500,000 New Cliff Vested Options.
Options Exercised and Stock Vested - 2009
None of the Named Executive Officers exercised any of his vested Stock Option Awards in 2009. In addition, none of the Named Executive Officers owned any restricted or deferred shares of EFH Corp. common stock that vested in 2009.
Pension Benefits -
The table set forth below illustrates present value on December 31, 2009 of each Named Executive Officer’s Retirement Plan benefit and benefits payable under the Supplemental Retirement Plan, based on their years of service and remuneration through December 31, 2009:
EFH Corp. and its participating subsidiaries maintain the Retirement Plan, which is intended to be qualified under applicable provisions of the Code and covered by ERISA. The Retirement Plan contains both a traditional defined benefit component and a cash balance component. Only employees hired before January 1, 2002 may participate in the traditional defined benefit component. Accordingly, none of the Named Executive Officers participates in the traditional defined benefit component. Employees hired after January 1, 2002 and before October 1, 2007 are eligible to participate in the cash balance component. In addition, effective December 31, 2009, certain assets and liabilities under the Salary Deferral Program and the Supplemental Retirement Plan were transferred to the cash balance component of the Retirement Plan. Accordingly, Messrs. Campbell and Burke have participated and may continue to participate in the cash balance component of the Retirement Plan; and Messrs. Young, Keglevic and Walters participate in the cash balance component of the Retirement Plan solely with respect to amounts that were transferred from the Salary Deferral Program.
Under the cash balance component of the Retirement Plan, hypothetical accounts are established for participants and credited with monthly contribution credits equal to a percentage of the participant’s compensation (3.5%, 4.5%, 5.5% or 6.5% depending on the participant’s combined age and years of accredited service), contribution credits equal to the amounts transferred from the Salary Deferral Program and/or the Supplemental Retirement Plan effective as of December 31, 2009 and interest credits on all of such amounts based on the average yield of the 30-year Treasury bond for the 12 months ending November 30 of the prior year.
The Supplemental Retirement Plan provides for the payment of retirement benefits, which would otherwise be limited by the Code or the definition of earnings under the Retirement Plan. Under the Supplemental Retirement Plan, retirement benefits under the cash balance component are calculated in accordance with the same formula used under the Retirement Plan. Participation in EFH Corp.’s Supplemental Retirement Plan has been limited to employees of all of its businesses other than Oncor, who were employed by EFH Corp. (or its participating subsidiaries) on or before October 1, 2007. Accordingly, Messrs. Campbell and Burke participate in the Supplemental Retirement Plan, and Messrs. Young, Keglevic and Walters are not eligible to participate in the Supplemental Retirement Plan.
Benefits accrued under the Supplemental Retirement Plan after December 31, 2004, are subject to Section 409A of the Code. Accordingly, certain provisions of the Supplemental Retirement Plan have been modified in order to comply with the requirements of Section 409A and related guidance.
The present value of the accumulated benefit for the Retirement Plan (the cash balance component) was calculated as the value of their cash balance account projected to age 65 at an assumed growth rate of 4.75% and then discounted back to December 31, 2009 at 5.90%. No mortality or turnover assumptions were applied.
Nonqualified Deferred Compensation - 2009(1)
The following table sets forth information regarding plans that provide for the deferral of the Named Executive Officers’ compensation on a basis that is not tax-qualified for the fiscal year ended December 31, 2009:
(1) The amounts reported in the Nonqualified Deferred Compensation table include deferrals and the company match under the Salary Deferral Program. The amounts reported as “Executive Contributions in Last FY” are salary deferrals and are also included as “Salary” in the Summary Compensation Table. Under EFH Corp.’s Salary Deferral Program each employee of EFH Corp. and its participating subsidiaries who is in a designated job level and whose annual salary is equal to or greater than an amount established under the Salary Deferral Program ($110,840 for the program year beginning January 1, 2009) may elect to defer up to 50% of annual base salary, and/or up to 100% of any bonus or incentive award, for a maturity period of seven years, for a maturity period ending with the retirement of such employee, or for a combination thereof. EFH Corp. makes a matching award, which vests at the end of the applicable maturity period (subject to acceleration or forfeiture under certain circumstances), equal to 100% of up to the first 8% of salary deferred under the Salary Deferral Program. Deferrals are credited with earnings or losses based on the performance of investment alternatives under the Salary Deferral Program selected by each participant. At the end of the applicable maturity period, the trustee for the Salary Deferral Program distributes the deferred compensation, any vested matching awards and the applicable earnings in cash as a lump sum or in annual installments at the participant’s election made at the time of deferral. EFH Corp. is financing the retirement option portion of the Salary Deferral Program through the purchase of corporate-owned life insurance on the lives of participants. The proceeds from such insurance are expected to allow EFH Corp. to fully recover the cost of the retirement option. Beginning in 2010, certain executive officers, including the Named Executive Officers, will not be eligible to participate in the Salary Deferral Program.
(2) The amount included in “Registrant Contributions in Last FY” is attributable to EFH Corp.’s matching award under the Salary Deferral Program.
(3) The “Aggregate Withdrawals/Distributions($)” column excludes amounts transferred from the Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan as of December 31, 2009 for Messrs. Young ($37,500), Keglevic ($48,511), Walters ($71,283) and Burke ($25,000). In accordance with the terms of the Salary Deferral Plan, Mr. Chand forfeited $39,606 of company matching and received a distribution of the remaining balance of his account upon termination of his employment.
(4) A portion of the amounts reported as “Aggregate Balance at Last FYE” are also included in the Summary Compensation Table as follows: for Mr. Young, $80,000 and $66,667 of executive contributions are included as “Salary” for 2009 and 2008, respectively, and $80,000 and $66,667 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively; for Mr. Keglevic, $48,000 and $20,000 of executive contributions are included as “Salary” for 2009 and 2008, respectively, and $48,000 and $20,000 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively; for Mr. Walters, $46,000 and $30,667 of executive contributions are included as “Salary” for 2009 and 2008, respectively, and $46,000 and $30,667 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively; for Mr. Burke, $48,000 and $27,417 of executive contributions are included as “Salary” for 2008 and 2007, respectively, and $48,000 and $27,417 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively. The amounts reported as “Aggregate Balance at Last FYE” reflect decreases resulting from the amounts transferred from the Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan as of December 31, 2009 for Messrs. Young ($37,500), Keglevic ($48,511), Walters ($71,283) and Burke ($25,000)
Potential Payments upon Termination or Change in Control
The tables and narrative below provide information for payments to each of the Named Executive Officers (or, as applicable, enhancements to payments or benefits) in the event of his termination, including if such termination is voluntary, for cause, as a result of death, as a result of disability, without cause or for good reason or without cause or for good reason in connection with a change in control.
The information in the tables below is presented in accordance with SEC rules, assuming termination of employment as of December 31, 2009.
Employment Arrangements with Contingent Payments
As of December 31, 2009, each of Messrs. Young, Keglevic, Campbell, Walters and Burke had employment agreements with change in control and severance provisions as described in the following tables. In addition, in October 2009, the O&C Committee approved several changes to the compensation arrangements for all of the Named Executive Officers other than Messrs. Young and Chand, which changes were effective as of December 31, 2009 but not yet documented in such Named Executive Officers’ employment agreements. Certain of these changes affected the potential payments of Messrs. Keglevic, Campbell, Walters and Burke and are reflected in the following tables. In February, 2010, Mr. Young’s employment agreement was amended and restated effective retroactively on January 1, 2010. Because the changes to Mr. Young’s employment agreement were not effective as of December 31, 2009, they are not reflected in the following table for Mr. Young, but are described elsewhere in this Form 10-K. Mr. Chand had an employment agreement, and the change in control and severance terms included in the employment agreement governed until his employment with EFH Corp. terminated in October 2009.
With respect to each Named Executive Officer’s employment agreement, a change in control is generally defined as (i) a transaction that results in a sale of substantially all of our assets to another person and such person having more seats on our Board than the Sponsor Group, (ii) a transaction that results in a person not in the Sponsor Group owning more than 50% of our common stock and such person having more seats on our Board than the Sponsor Group or (iii) a transaction that results in the Sponsor Group owning less than 20% of our common stock and the Sponsor Group not being able to appoint a majority of the directors to our Board.
Each Named Executive Officer’s employment agreement includes customary non-compete and non-solicitation provisions that generally restrict the Named Executive Officer’s ability to compete with us or solicit our customers or employees for his own personal benefit during the term of the employment agreement and 24 months (with respect to Mr. Young) or 18 months (with respect to Messrs. Keglevic, Campbell, Walters and Burke) after the employment agreement expires or is terminated.
In addition, in October 2009, the O&C Committee approved the adoption of a new LTI to be included by amendment in the employment agreement of Messrs. Keglevic, Campbell, Walters and Burke. Under the terms of the LTI, in the event of the death or disability of any such Named Executive Officer, his termination without cause or resignation for good reason (or in the event we elect not to extend his employment term), or his termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp., in each case prior to September 30, 2012, such named Executive Officer shall be entitled to receive the LTI, or a pro rata portion thereof, calculated as (i) 75% of the aggregate EAIP award actually earned by the Named Executive Officer for any applicable fiscal year completed prior to the date of the Named Executive Officer’s termination, plus (ii) for a termination occurring in fiscal year 2009, 2010, or 2011, 75% of the Named Executive Officer’s prorated annual performance-based cash bonus for the year of termination. In February 2010, Mr. Young’s employment agreement was amended to add a similar new LTI that is calculated based on 100% of the aggregate EAIP award actually earned by Mr. Young for fiscal years 2009, 2010 and 2011.
As of December 31, 2009, each of Messrs. Young, Keglevic, Campbell, Walters and Burke had stock option agreements. Under the stock option agreement for each Named Executive Officer, in the event of such Named Executive Officer’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) following a change in control of EFH Corp., such Named Executive Officer’s Original Time Vested Options would become immediately exercisable as to 100% of the shares of EFH Corp. common stock subject to such options immediately prior to the change in control. As of December 31, 2009, the fair market value of the shares of EFH Corp. common stock underlying each Named Executive Officer’s Original Time Vested Options was less than the exercise price of such options.
1. Mr. Young
Potential Payments to Mr. Young upon Termination as of December 31, 2009 (per employment agreement, restricted stock agreement and stock option agreement, each in effect as of December 31, 2009)
Mr. Young has entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
1. In the event of Mr. Young’s death or disability:
a. a prorated annual incentive bonus for the year of termination, and
b. payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled.
2. In the event of Mr. Young’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):
a. a lump sum payment equal to two and one-half times the sum of (i) his annualized base salary and (ii) a prorated annual incentive bonus for the year of termination;
b. payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled, and
c. certain continuing health care and company benefits.
3. In the event of Mr. Young’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:
a. a lump sum payment equal to two and one-half times the sum of (i) his annualized base salary and (ii) his annual bonus target;
b. a prorated annual incentive bonus for the year of termination;
c. payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled;
d. certain continuing health care and company benefits, and
e. a tax gross-up payment to offset any excise tax which may result from the change in control payments.
In addition, Mr. Young has entered into a restricted stock agreement. Under Mr. Young’s restricted stock agreement, Mr. Young was granted 600,000 restricted stock units, payable in January 2010, with one share of common stock of EFH Corp. for each such unit, all of which were fully vested and nonforfeitable upon grant; provided, however, in the event of Mr. Young’s voluntary termination prior to January 2010, Mr. Young would have had to forfeit all of his restricted stock units.
2. Mr. Keglevic
Potential Payments to Mr. Keglevic upon Termination as of December 31, 2009 (per employment agreement, deferred share agreement and stock option agreement, each in effect as of December 31, 2009, and revisions to such employment agreement that were adopted by the O&C Committee in October 2009 and effective as of December 31, 2009)
Mr. Keglevic entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
1. In the event of Mr. Keglevic’s death or disability:
a. a prorated annual incentive bonus for the year of termination, and
b. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled.
2. In the event of Mr. Keglevic’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):
a. for a termination occurring on or prior to the second anniversary of the effective date of the agreement, a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target, and for a termination occurring after the second anniversary of the effective date of the agreement, a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination and (iii) the matching contributions which would have been made on his behalf to EFH Corp.’s Salary Deferral Program had Mr. Keglevic continued his participation in the plan for an additional twelve months;
b. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled, and
c. certain continuing health care and company benefits.
3. In the event of Mr. Keglevic’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:
a. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target;
b. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled;
c. certain continuing health care and company benefits, and
d. a tax gross-up payment to offset any excise tax which may result from the change in control payments.
In addition, Mr. Keglevic has entered into a deferred share agreement. Under Mr. Keglevic’s deferred share agreement, EFH Corp. agreed to deliver to Mr. Keglevic 112,500 shares of EFH Corp. common stock on July 1, 2011 and 112,500 shares of EFH Corp. common stock on July 1, 2013; provided, however, that any shares not yet vested shall become 100% vested and become nonforfeitable in the event of Mr. Keglevic’s death or disability or as a result of his termination without cause or for good reason or without cause or for good reason in connection with a change in control. Further, in the event of Mr. Keglevic’s termination prior to July 1, 2013 as a result of death, as a result of disability, without cause or for good reason or without cause or for good reason in connection with a change in control, Mr. Keglevic shall have the right (but not the obligation) to sell to EFH Corp. all (but not less than all) of the shares of EFH Corp. common stock delivered pursuant to the deferred share agreement for a purchase price of $3,200,000.
3. Mr. Campbell
Potential Payments to Mr. Campbell upon Termination as of December 31, 2009 (per employment agreement, deferred share agreement and stock option agreement, each in effect as of December 31, 2009, and revisions to such employment agreement that were adopted by the O&C Committee in October 2009 and effective as of December 31, 2009)
(1) Mr. Campbell is fully vested in the company matching portion of the Salary Deferral Plan.
Mr. Campbell entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
1. In the event of Mr. Campbell’s death or disability:
a. a prorated annual incentive bonus for the year of termination, and
b. payment of employee benefits, including stock compensation, if any, to which Mr. Campbell may be entitled.
2. In the event of Mr. Campbell’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):
a. for a termination occurring on or prior to the second anniversary of the effective date of the agreement, a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target, and for a termination occurring after the second anniversary of the effective date of the agreement, a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination and (iii) the matching contributions which would have been made on his behalf to EFH Corp.’s
Salary Deferral Program had Mr. Campbell continued his participation in the plan for an additional twelve months;
b. payment of employee benefits, including stock compensations, if any, to which Mr. Campbell may be entitled, and
c. certain continuing health care and company benefits.
3. In the event of Mr. Campbell’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:
a. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target;
b. payment of employee benefits, including stock compensation, if any, to which Mr. Campbell may be entitled;
c. certain continuing health care and company benefits, and
d. a tax gross-up payment to offset any excise tax which may result from the change in control payments.
In addition, Mr. Campbell has entered into a deferred share agreement. Under Mr. Campbell’s deferred share agreement, EFH Corp. agreed to deliver to Mr. Campbell 500,000 shares of EFH Corp. common stock in the event of Mr. Campbell’s termination for any reason.
4. Mr. Walters
Potential Payments to Mr. Walters upon Termination as of December 31, 2009 (per employment agreement and stock option agreement, each in effect as of December 31, 2009, and revisions to such employment agreement that were adopted by the O&C Committee in October 2009 and effective as of December 31, 2009)
Mr. Walters entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
1. In the event of Mr. Walters’ death or disability:
a. a prorated annual incentive bonus for the year of termination;
b. a lump sum payment equal to $2,000,000, and
c. payment of employee benefits, including stock compensation, if any, to which Mr. Walters may be entitled.
2. In the event of Mr. Walters’ termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):
a. for a termination occurring on or prior to the second anniversary of the effective date of the agreement, a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target, and for a termination occurring after the second anniversary of the effective date of the agreement, a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination and (iii) the matching contributions which would have been made on his behalf to EFH Corp.’s Salary Deferral Program had Mr. Walters continued his participation in the plan for an additional twelve months;
b. a lump sum payment equal to $2,000,000;
c. payment of employee benefits, including stock compensation, if any, to which Mr. Walters may be entitled, and
d. certain continuing health care and company benefits.
3. In the event of Mr. Walters’ termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:
a. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target;
b. a lump sum payment equal to $2,000,000;
c. payment of employee benefits, including stock compensation, if any, to which Mr. Walters may be entitled;
d. certain continuing health care and company benefits, and
e. a tax gross-up payment to offset any excise tax which may result from the change in control payments.
5. Mr. Burke
Potential Payments to Mr. Burke upon Termination as of December 31, 2009 (per employment agreement and stock option agreement, each in effect as of December 31, 2009, and revisions to such employment agreement that were adopted by the O&C Committee in October 2009 and effective as of December 31, 2009)
Mr. Burke entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
1. In the event of Mr. Burke’s death or disability:
a. a prorated annual incentive bonus for the year of termination, and
b. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled.
2. In the event of Mr. Burke’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):
a. a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination and (iii) the matching contributions which would have been made on his behalf to EFH Corp.’s Salary Deferral Program had Mr. Burke continued his participation in the plan for an additional twelve months;
b. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled, and
c. certain continuing health care and company benefits.
3. In the event of Mr. Burke’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:
a. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target;
b. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled;
c. certain continuing health care and company benefits and
d. a tax gross-up payment to offset any excise tax which may result from the change in control payments.
6. Mr. Chand
Mr. Chand’s employment with EFH Corp. terminated in October 2009. Under the terms of his Severance Agreement, EFH Corp. provided Mr. Chand a severance payment which consisted of a lump sum cash payment of (i) $1,485,000, representing the cash severance that was due under his employment agreement and (ii) $600,000 related to his deferred share agreement.
Excise Tax Gross-Ups
Pursuant to their employment agreements, if any of our Named Executive Officers would be subject to the imposition of the excise tax imposed by Section 4999 of the Code, related to the executive’s employment, but the imposition of such tax could be avoided by approval of our shareholders as described in Section 280G(b)(5)(B) of the Code, then such executive may cause EFH Corp. to seek such approval, in which case EFH Corp. will use its reasonable best efforts to cause such approval to be obtained and such executive will cooperate and execute such waivers as may be necessary so that such approval avoids imposition of any excise tax under Section 4999. If such executive fails to cause EFH Corp. to seek such approval or fails to cooperate and execute the waivers necessary in the approval process, such executive shall not be entitled to any gross-up payment for any resulting tax under Section 4999.
Compensation Committee Interlocks and Insider Participation
There are no relationships among our executive officers, members of the O&C Committee or entities whose executives served on the O&C Committee that required disclosure under applicable SEC rules and regulations. For a description of related person transactions involving members of the O&C Committee, see Item 13, entitled “Related Person Transactions.”
Director Compensation
The table below sets forth information regarding the aggregate compensation paid to the members of the Board during the year ended December 31, 2009. Directors who are officers of EFH Corp. or members of the Sponsor Group (or their respective affiliates) do not receive any fees for service as a director. EFH Corp. reimburses directors for certain reasonable expenses incurred in connection with their services as directors.
(1) Ms. Acosta and Messrs. Huffines, Olson, Reilly and Youngblood receive $150,000 annually and an annual equity award (paid in shares of EFH Corp. common stock) valued at $100,000 (the grant date fair value) for their service as a director.
(2) In May 2008, EFH Corp. entered into a consulting agreement with Mr. Evans, pursuant to which he received the following compensation:
1. An annual fee of $2,000,000; and
2. 200,000 shares of restricted stock, half of which vested during 2009, 50,000 shares at $5.00 per share and 50,000 shares at $3.50 per share. The value of the shares that vested during 2009 is reported in the table above under the heading “Stock Awards”.
Under the consulting agreement, Mr. Evans also received options to purchase 600,000 shares of EFH Corp.’s common stock at an exercise price of $5.00 per share. As a result, there should have been an “Option Awards” column in last year’s Director Compensation table and it should have included $551,250 as the grant date fair value for the options granted to Mr. Evans in May 2008 based upon rules for valuing stock option awards as they existed last year. The consulting agreement had a term running through October 2009. In February 2010, EFH Corp. entered into a new consulting agreement with Mr. Evans effective retroactively to October 10, 2009, pursuant to which Mr. Evans is entitled to receive an annual fee of $2,000,000. The term of the new consulting agreement expires in October 2012.
(3) In December 2007, EFH Corp. entered into consulting agreements with Messrs. Huffines and Olson. As compensation for their consulting services, they received annual fees of $225,000, in addition to their standard director compensation described above. The amounts earned pursuant to these consulting agreements in 2009 are reflected above in the “All Other Compensation” column. In November 2009, the consulting agreements with Messrs. Huffines and Olson were terminated. In January 2010, Messrs. Huffines and Olson were each paid a $675,000 bonus for their exemplary efforts and past performance while serving as consultants.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The following table presents information concerning stock-based compensation plans as of December 31, 2009. (See Note 22 to Financial Statements.)
Note:
Includes 49.8 million stock options with a weighted average exercise price of $4.63.
Includes 4.0 million vested and unvested restricted shares, deferred shares and stock granted to directors as part of their compensation plan.
Beneficial Ownership of Common Stock of Energy Future Holdings Corp.
The following table lists the number of shares of common stock of EFH Corp. beneficially owned by each director and certain current and former executive officers of EFH Corp. and the holders of more than 5% of EFH Corp.’s common stock as of February 1, 2010.
* Less than 1%.
(1) Texas Holdings beneficially owns 1,657,600,000 shares of EFH Corp. The sole general partner of Texas Holdings is Texas Energy Future Capital Holdings LLC (Texas Capital), which, pursuant to the Amended and Restated Limited Partnership Agreement of Texas Holdings, has the right to vote all of the EFH Corp. shares owned by Texas Holdings. The address of both Texas Holdings and Texas Capital is 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.
(2) Shares held in a family limited partnership, ACA Family LP.
(3) Includes the 1,657,600,000 shares owned by Texas Holdings, over which TPG Partners V, L.P., TPG Partners IV, L.P., TPG FOF V-A, L.P. and TPG FOF V-B, L.P. (TPG Entities) may be deemed, as a result of their ownership of 27.01% of Texas Capital’s outstanding units and certain provisions of Texas Capital’s Amended and Restated Limited Liability Company Agreement (TC LLC Agreement), to have shared voting or dispositive power. The ultimate general partners of the TPG Entities are TPG Advisors IV, Inc. and TPG Advisors V, Inc. David Bonderman and James Coulter are the sole shareholders and directors of TPG Advisors IV Inc. and TPG Advisors V Inc., and therefore, Messrs. Bonderman and Coulter, TPG Advisors IV Inc. and TPG Advisors V Inc. may each be deemed to beneficially own the shares held by the TPG Entities. Messrs. Bonderman, Liaw and MacDougall are managers of Texas Capital. By virtue of their position in relation to Texas Capital and the TPG Entities, Messrs. Bonderman, Liaw and MacDougall may be deemed to have beneficial ownership with respect to the shares of EFH Corp. common stock owned by Texas Holdings. Each of Messrs. Liaw and MacDougall disclaims beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.
(4) Includes 600,000 shares issuable upon exercise of vested options.
(5) Includes the 1,657,600,000 shares owned by Texas Holdings, over which GS Capital Partners VI Fund, L.P., GSCP VI Offshore TXU Holdings, L.P., GSCP VI Germany TXU Holdings, L.P., GS Capital Partners VI Parallel, L.P., GS Global Infrastructure Partners I, L.P., GS Infrastructure Offshore TXU Holdings, L.P. (GSIP International Fund), GS Institutional Infrastructure Partners I, L.P., Goldman Sachs TXU Investors L.P. and Goldman Sachs TXU Investors Offshore Holdings, L.P. (collectively, Goldman Entities) may be deemed, as a result of their ownership of 27.02% of Texas Capital’s outstanding units and certain provision of the TC LLC Agreement, to have shared voting or dispositive power. Affiliates of The Goldman Sachs Group, Inc. (Goldman Sachs) are the general partner, managing general partner or investment manager of each of the Goldman Entities, and each of the Goldman Entities shares voting and investment power with certain of their respective affiliates. Each of Goldman Sachs and the Goldman Entities disclaims beneficial ownership of such shares of common stock except to the extent of its pecuniary interest therein. Messrs. Ferguson, Lebovitz and Pontarelli are managers of Texas Capital and executives with affiliates of Goldman Sachs. By virtue of their position in relation to Texas Capital and the Goldman Entities, Messrs. Ferguson, Lebovitz and Pontarelli may be deemed to have beneficial ownership with respect to the shares of EFH Corp. common stock owned by Texas Holdings. Each of Messrs. Ferguson, Lebovitz and Pontarelli disclaims beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is c/o Goldman, Sachs & Co., 85 Broad Street, New York, New York 10004.
(6) Includes the 1,657,600,000 shares owned by Texas Holdings, over which KKR 2006 Fund L.P., KKR PEI Investments, L.P., KKR Partners III, L.P., KKR North American Co-Invest Fund I L.P. and TEF TFO Co-Invest, LP (KKR Entities) may be deemed, as a result of their ownership of 37.05% of Texas Capital’s outstanding units and certain provision of the TC LLC Agreement, to have shared voting or dispositive power. The KKR Entities disclaim beneficial ownership of any shares of our common stock in which they do not have a pecuniary interest. Messrs. Goltz, Lipschultz and Smidt are managers of Texas Capital and executives of Kohlberg Kravis Roberts & Co. L.P. By virtue of their position in relation to Texas Capital and the KKR Entities, Messrs. Goltz, Lipschultz and Smidt may be deemed to have beneficial ownership with respect to the shares of EFH Corp. common stock owned by Texas Holdings. Each of Messrs. Goltz, Lipschultz and Smidt disclaims beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57th Street, Suite 4200, New York, New York 10019.
(7) Includes 2,250,000 shares issuable upon exercise of vested options.
(8) Includes 450,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 735,000 shares issuable upon exercise of vested options.
(9) Includes 500,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 1,200,000 shares issuable upon exercise of vested options.
(10) Includes 350,000 shares issuable upon exercise of vested options.
(11) Includes 225,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 750,000 shares issuable upon exercise of vested options.
(12) Includes 600,000 shares issuable upon exercise of vested options.
(13) Includes 100,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 400,000 shares issuable upon exercise of vested options.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Policies and Procedures Relating to Related Party Transactions
The Board has adopted a policy regarding related person transactions. Under this policy, a related person transaction shall be consummated or shall continue only if:
1. the Audit Committee of the Board approves or ratifies such transaction in accordance with the policy and if the transaction is on terms comparable to those that could be obtained in arm’s length dealings with an unrelated third party;
2. the transaction is approved by the disinterested members of the Board or the Executive Committee; or
3. the transaction involves compensation approved by the Organization and Compensation Committee of the Board.
For purposes of this policy, the term “related person” includes EFH Corp.’s directors, executive officers, 5% shareholders and their immediate family members. “Immediate family members” means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law or any person (other than a tenant or employee) sharing the household of a director, executive officer or 5% shareholder.
A “related person transaction” is a transaction between EFH Corp. or its subsidiaries and a related person, other than the types of transactions described below, which are deemed to be pre-approved by the Audit Committee of the Board:
1. any compensation paid to a director if the compensation is required to be reported under Item 402 of Regulation S-K of the Securities Act;
2. any transaction with another company at which a related person’s only relationship is as an employee (other than an executive officer), director or beneficial owner of less than 10% of that company’s ownership interests;
3. any charitable contribution, grant or endowment by EFH Corp. to a charitable organization, foundation or university at which a related person’s only relationship is as an employee (other than an executive officer) or director;
4. transactions where the related person’s interest arises solely from the ownership of EFH Corp.’s equity securities and all holders of that class of equity securities received the same benefit on a pro rata basis;
5. transactions involving a related party where the rates or charges involved are determined by competitive bids;
6. any transaction with a related party involving the rendering of services as a common or contract carrier, or public utility, as rates or charges fixed in conformity with law or governmental authority;
7. any transaction with a related party involving services as a bank depositary of funds, transfer agent, registrar, trustee under a trust indenture, or similar service;
8. transactions available to all employees or customers generally (unless required to be disclosed under Item 404 of Regulation S-K of the Securities Act, if applicable);
9. transactions involving less than $100,000 when aggregated with all similar transactions;
10. transactions between EFH Corp. and its subsidiaries or between subsidiaries of EFH Corp.;
11. transactions not required to be disclosed under Item 404 of Regulation S-K under the Securities Act of 1933, and
12. open market purchases of the EFH Corp. or its subsidiaries’ debt or equity securities and interest payments on such debt.
The Board has determined that it is appropriate for the Audit Committee of the Board to review and approve or ratify related person transactions. Accordingly, at least annually, management reviews related person transactions to be entered into by EFH Corp. or its subsidiaries, if any. After review, the Audit Committee of the Board approves/ratifies or disapproves such transactions. Management updates the Audit Committee of the Board as to any material changes to such related person transactions. In unusual circumstances, EFH Corp. or its subsidiaries may enter into related person transactions in advance of receiving approval, provided that such related person transactions are reviewed and ratified as soon as reasonably practicable by the Audit Committee of the Board. If the Audit Committee of the Board determines not to ratify such transactions, EFH Corp. shall make all reasonable efforts to cancel or otherwise terminate such transactions.
The related person transactions described below under “Related Person Transactions - Business Affiliations,” were ratified by the Audit Committee of the Board pursuant to the policy described above. All other related person transactions were approved prior to the Board’s adoption of this policy, but were approved by either the Board or its Executive Committee. Transactions described below under “Related Person Transactions - Transactions with Sponsor Affiliates” are not related person transactions under the EFH Corp. policy because they are not with a director, executive officer, 5% shareholder or any of their immediate family members, but are described in the interest of greater disclosure.
Related Person Transactions
Limited Partnership Agreement of Texas Energy Future Holdings Limited Partnership; Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC
The Sponsor Group and certain investors who agreed to co-invest with the Sponsor Group or through a vehicle jointly controlled by the Sponsor Group to provide equity financing for the Merger (Co-Investors) entered into (i) a limited partnership agreement (LP Agreement) in respect of EFH Corp.’s parent company, Texas Holdings and (ii) the LLC Agreement in respect of Texas Holdings’ sole general partner, Texas Capital. The LP Agreement provides that Texas Capital has the right to vote or execute consents with respect to any shares of EFH Corp.’s common stock owned by Texas Holdings. The LLC Agreement and LP Agreement contain agreements among the parties with respect to the election of EFH Corp.’s directors, restrictions on the issuance or transfer of interests in EFH Corp., including tag-along rights and drag-along rights, and other corporate governance provisions (including the right to approve various corporate actions).
The LLC Agreement provides that Texas Capital and its members will take all action required to ensure that the managers of Texas Capital are also members of EFH Corp.’s Board. Pursuant to the LLC Agreement each of (i) KKR 2006 Fund L.P. and affiliated investment funds, (ii) TPG Partners V, L.P. and affiliated investment funds and (iii) certain funds affiliated with Goldman Sachs, has the right to designate three managers of Texas Capital. These rights are subject to maintenance of certain investment levels in Texas Holdings.
Registration Rights Agreement
The Sponsor Group and the Co-Investors entered into a registration rights agreement with EFH Corp. upon completion of the Merger. Pursuant to this agreement, in certain circumstances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.’s common stock owned directly or indirectly by them under the Securities Act. In certain circumstances, the Sponsor Group and the Co-Investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.’s common stock under the Securities Act that it may undertake. In 2008 and 2009, Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly and Youngblood, each of whom are members of our Board, and Messrs. Young, Greene, Campbell, Walters, Burke, Keglevic, McFarland, Enze, Kaplan and Landy, each of whom are executive officers of EFH Corp., became parties to this agreement.
Management Services Agreement
In October 2007, in connection with the Merger, the Sponsor Group and Lehman Brothers Inc. entered into a management agreement with EFH Corp. (Management Agreement), pursuant to which affiliates of the Sponsor Group provide management, consulting, financial and other advisory services to EFH Corp. Pursuant to the Management Agreement, affiliates of the Sponsor Group are entitled to receive an aggregate annual management fee of $35 million, which amount increases 2% annually, and reimbursement of out-of-pocket expenses incurred in connection with the provision of services pursuant to the Management Agreement. The Management Agreement will continue in effect from year to year, unless terminated upon a change of control of EFH Corp. or in connection with an initial public offering of EFH Corp. or if the parties thereto mutually agree to terminate the Management Agreement. Pursuant to the Management Agreement, affiliates of the Sponsor Group and Lehman Brothers Inc. were paid transaction fees of $300 million for certain services provided in connection with the Merger and related transactions. In addition, the Management Agreement provides that the Sponsor Group will be entitled to receive a fee equal to a percentage of the gross transaction value in connection with certain subsequent financing, acquisition, disposition, merger combination and change of control transactions, as well as a termination fee based on the net present value of future payment obligations under the Management Agreement in the event of an initial public offering or under certain other circumstances. Under terms of the Management Agreement, EFH Corp. paid $36 million, inclusive of expenses, to the Sponsor Group during 2009.
Indemnification Agreement
Concurrently with entering into the Management Agreement, the Sponsor Group, Texas Holdings and EFH Corp. entered into an indemnification agreement (Indemnification Agreement), pursuant to which EFH Corp. and Texas Holdings agree to indemnify the Sponsor Group and their affiliates against any claims relating to (i) certain securities and financing transactions relating to the Merger, (ii) the performance of transaction services pursuant to the Management Agreement, (iii) actions or failures to act by EFH Corp., Texas Holdings, Texas Capital or their subsidiaries or affiliates (collectively, Company Group), (iv) service as an officer or director of, or at the request of, any member of the Company Group, and (v) any breach or alleged breach of fiduciary duty as a director or officer of any member of the Company Group.
Sale Participation Agreement
Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly and Youngblood, each of whom are members of our Board, and each of our executive officers have entered into sale participation agreements with EFH Corp. Pursuant to the terms of these agreements, among other things, shares of EFH Corp.’s common stock held by these individuals are subject to tag-along and drag-along rights in the event of a sale by the Sponsor Group of shares of EFH Corp.’s common stock held by the Sponsor Group.
Certain Charter Provisions
EFH Corp.’s restated certificate of formation contains provisions limiting directors’ obligations in respect of corporate opportunities.
Management Stockholders’ Agreement
Subject to a management stockholders’ agreement, certain members of management, including EFH Corp.’s directors, executive officers, along with other members of management, elected to invest in EFH Corp. by contributing cash or common stock, or a combination of both, to EFH Corp. prior to or following the Merger and receiving common stock in EFH Corp. in exchange therefore. The net aggregate amount of this investment as of December 31, 2009 is approximately $42.6 million. The management stockholders’ agreement creates certain rights and restrictions on these shares of common stock, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances.
Director Stockholders’ Agreement
Certain members of our Board have entered into a stockholders’ agreement with EFH Corp. These stockholders’ agreements create certain rights and restrictions on the equity, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances.
Business Affiliations
Mr. Olson, a member of our board, has an ownership interest in two companies with which Oncor does business. These companies are Texas Meter and Device Company (TMD) and Metrum Technologies LLC (Metrum). Mr. Olson and his brother collectively directly own approximately 24% of TMD and indirectly own approximately 19% of Metrum. Both entities are majority owned by their chief executive officer. In 2009, Oncor paid TMD approximately $1.2 million and paid Metrum approximately $0.2 million. TMD tests Oncor’s high voltage personal protective equipment. Metrum provides Oncor with cellular-based wireless communications equipment for its meters. Oncor is Metrum’s largest customer. The business relationships with both TMD and Metrum commenced several years prior to Mr. Olson joining the Board.
Transactions with Sponsor Affiliates
TCEH has entered into the TCEH Senior Secured Facilities, and Oncor has entered into a revolving credit facility, each with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners. These transactions were approved by the Board of Directors.
Affiliates of the Sponsor Group participated in the debt exchange offers completed in November 2009 by EFH Corp., Intermediate Holding and EFIH Finance to exchange new senior secured notes for certain EFH Corp. and TCEH notes (see Note 12 to Financial Statements for additional information). Goldman, Sachs & Co. and KKR Capital Markets LLC were paid customary fees in the amounts of $750,000 and $260,000, respectively, as compensation for their services as dealer managers in the debt exchange offers and TPG Capital, L.P. received a fee in the amount of $260,000 as compensation for the advisory services it rendered in connection with the debt exchange offers.
Also, Goldman, Sachs & Co. acted as an initial purchaser in EFH Corp.’s issuance of $500 million principal amount of senior secured notes completed in January 2010. (See Note 12 to Financial Statements for additional information.)
Affiliates of GS Capital Partners have from time to time engaged in commercial and investment banking and financial advisory transactions with EFH Corp. in the normal course of business. Affiliates of Goldman Sachs & Co. are party to certain commodity and interest rate hedging transactions with EFH Corp. in the normal course of business.
From time to time affiliates of the Sponsor Group may acquire debt or debt securities issued by EFH Corp. or its subsidiaries in open market transactions or through loan syndications.
Members of the Sponsor Group and/or their respective affiliates have from time to time entered into, and may continue to enter into, arrangements with us to use our products and services in the ordinary course of their business, which often result in revenues to us in excess of $120,000 annually. In addition, we have entered into, and may continue to enter into, arrangements with members of the Sponsor Group and/or their respective affiliates to use their products and services in the ordinary course of their business, which often result in revenues to members of the Sponsor Group or their respective affiliates in excess of $120,000 annually.
Director Independence
Though not formally considered by the Board because EFH Corp.’s common stock is not currently registered with the SEC or traded on any national securities exchange, based upon the listing standards for issuers of equity securities on the New York Stock Exchange, the national securities exchange upon which EFH Corp.’s common stock was traded prior to the Merger, only Ms. Acosta and Mr. Youngblood would be considered independent. Because of their relationships with the Sponsor Group or with EFH Corp. directly, none of the other directors would be considered independent. See “Certain Relationships and Related Party Transactions” and Item 11, “Executive Compensation - Director Compensation.” Accordingly, we believe that Ms. Acosta is the only member of the Organization and Compensation Committee who would meet the New York Stock Exchange’s independence requirements for issuers of equity securities. We believe that none of the members of EFH Corp.’s Governance and Public Affairs Committee would meet the New York Stock Exchange’s independence requirements for issuers of equity securities. Under the New York Stock Exchange’s audit committee independence requirement for issuers of debt securities, Messrs. Huffines and Youngblood and Ms. Acosta, who constitute the Audit Committee, are considered independent.
Item 14.
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Deloitte & Touche LLP has been the independent auditor for EFH Corp. and for its Predecessor (TXU Corp.) since its organization in 1996.
The Audit Committee of the EFH Corp. Board of Directors has adopted a policy relating to the engagement of EFH Corp.’s independent auditor. The policy provides that in addition to the audit of the financial statements, related quarterly reviews and other audit services, and providing services necessary to complete SEC filings, EFH Corp.’s independent auditor may be engaged to provide non-audit services as described herein. Prior to engagement, all services to be rendered by the independent auditor must be authorized by the Audit Committee in accordance with pre-approval procedures which are defined in the policy. The pre-approval procedures require:
1. The annual review and pre-approval by the Audit Committee of all anticipated audit and non-audit services; and
2. The quarterly pre-approval by the Audit Committee of services, if any, not previously approved and the review of the status of previously approved services.
The Audit Committee may also approve certain on-going non-audit services not previously approved in the limited circumstances provided for in the SEC rules. All services performed by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates ("Deloitte & Touche") for EFH Corp. in 2009 were pre-approved by the Audit Committee.
The policy defines those non-audit services which EFH Corp.’s independent auditor may also be engaged to provide as follows:
1. Audit-related services, including:
a. due diligence accounting consultations and audits related to mergers, acquisitions and divestitures;
b. employee benefit plan audits;
c. accounting and financial reporting standards consultation;
d. internal control reviews, and
e. attest services, including agreed-upon procedures reports that are not required by statute or regulation.
2. Tax-related services, including:
a. tax compliance;
b. general tax consultation and planning;
c. tax advice related to mergers, acquisitions, and divestitures, and
d. communications with and request for rulings from tax authorities.
3. Other services, including:
a. process improvement, review and assurance;
b. litigation and rate case assistance;
c. forensic and investigative services, and
d. training services.
The policy prohibits EFH Corp. from engaging its independent auditor to provide:
1. Bookkeeping or other services related to EFH Corp.’s accounting records or financial statements;
2. Financial information systems design and implementation services;
3. Appraisal or valuation services, fairness opinions, or contribution-in-kind reports;
4. Actuarial services;
5. Internal audit outsourcing services;
6. Management or human resource functions;
7. Broker-dealer, investment advisor, or investment banking services;
8. Legal and expert services unrelated to the audit, and
9. Any other service that the Public Company Accounting Oversight Board determines, by regulation, to be impermissible.
In addition, the policy prohibits EFH Corp.’s independent auditor from providing tax or financial planning advice to any officer of EFH Corp.
Compliance with the Audit Committee’s policy relating to the engagement of Deloitte & Touche is monitored on behalf of the Audit Committee by EFH Corp.’s chief internal audit executive. Reports describing the services provided by Deloitte & Touche and fees for such services are provided to the Audit Committee no less often than quarterly.
For the years ended December 31, 2009 and 2008, fees billed to EFH Corp. by Deloitte & Touche were as follows:
PART IV
Item 15.
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Oncor Holdings Financial Statements are presented pursuant to Item 3 - 16 of Regulation S-X as Exhibit 99(d).
(b) Exhibits:
EFH Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2009
* Incorporated herein by reference
** Certain instruments defining the rights of holders of long-term debt of the registrant’s subsidiaries included in the financial statements filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10 percent of the total assets of the registrant and its subsidiaries on a consolidated basis. Registrant hereby agrees, upon request of the SEC, to furnish a copy of any such omitted instrument.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Energy Future Holdings Corp. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Energy Future Holdings Corp. and in the capacities and on the date indicated.