Item 1A.   Risk Factors

 

FORWARD-LOOKING STATEMENTS

 

This Form 10-K includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements.”  All statements included or incorporated by reference in this annual report, other than statements of historical fact, that address activities, events or developments that we or our management expect, believe or anticipate will or may occur in the future are forward-looking statements.  These statements represent our reasonable judgment on the future based on various factors and using numerous assumptions and are subject to known and unknown risks, uncertainties and other factors that could cause our actual results and financial position to differ materially from those contemplated by the statements.  You can identify these statements by the fact that they do not relate strictly to historical or current facts.  They use words such as “anticipate,” “estimate,” “project,” “forecast,” “plan,” “may,” “will”, “should”, “expect” and other words of similar meaning.  In particular, these include, but are not limited to, statements relating to the following:

 

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beliefs and assumptions regarding our ability to continue as a going concern;

 

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the impact of the turnover in our executive team and Dynegy’s Board of Directors on our ability to execute our business plan;

 

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beliefs and assumptions relating to our liquidity, available borrowing capacity and capital resources generally, including the extent to which such liquidity could be affected by poor economic and financial market conditions or new regulations and any resulting impacts on financial institutions and other current and potential counterparties;

 

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the outcome of any legal proceedings that may be instituted against Dynegy and/or others relating to the Blackstone Merger Agreement and Icahn Merger Agreement;

 

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diversion of management’s attention from ongoing business concerns;

 

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limitations on our ability to utilize Dynegy’s previously incurred federal net operating losses or alternative minimum tax credits;

 

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the amount of the costs, fees, expenses, and other charges related to the Blackstone Merger Agreement and the Icahn Merger Agreement;

 

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the timing and anticipated benefits to be achieved through our company-wide cost savings programs;

 

 

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expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations to which we are, or could become, subject;

 

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beliefs, assumptions and projections regarding the overall economy, demand for power, generation volumes and commodity pricing , including natural gas prices and the impact on such prices from shale gas proliferation and the timing of a recovery in natural gas prices, if any;

 

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sufficiency of, access to and costs associated with coal, fuel oil and natural gas inventories and transportation thereof;

 

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beliefs and assumptions about market competition, generation capacity and regional supply and demand characteristics of the wholesale power generation market, including the anticipation of  higher market pricing over the longer term;

 

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the possibility of further consolidation in the power generation industry and the impact of any such activity on Dynegy;

 

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beliefs and assumptions regarding our ability to enhance or protect long-term value for stockholders;

 

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the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility;

 

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beliefs and assumptions about weather and general economic conditions;

 

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projected operating or financial results, including anticipated cash flows from operations, revenues and profitability;

 

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expectations regarding our revolver capacity, credit facility compliance, financial covenants, collateral demands, capital expenditures, interest expense and other payments;

 

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beliefs or expectations regarding the potential amendment or refinancing of our Credit Facility, or the timing thereof;

 

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our focus on safety and our ability to efficiently operate our assets so as to capture revenue generating opportunities and operating margins;

 

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beliefs about the outcome of legal, regulatory, administrative and legislative matters; and

 

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expectations regarding performance standards and estimates regarding capital and maintenance expenditures, including the Midwest Consent Decree and its associated costs and performance standards.

 

Any or all of our forward-looking statements may turn out to be wrong.  They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors, many of which are beyond our control, including those set forth below.

 

FACTORS THAT MAY AFFECT FUTURE RESULTS

 

Risks Related to Our Financial Structure, Level of Indebtedness and Access to Capital Markets

 

We have received audit reports on our consolidated financial statements that express uncertainty about our ability to continue as a going concern.

 

Our independent registered public accounting firm has included an explanatory paragraph in their reports on our December 31, 2010, 2009 and 2008 consolidated financial statements regarding doubt as to our ability to continue as a going concern. This may have a negative impact on the trading price of Dynegy's common stock and may make it more difficult to amend or replace our current Credit Facility, or to seek additional sources of liquidity.

 

 

We have significant debt that could negatively impact our business.

 

We have and will continue to have a significant amount of debt outstanding.  As of December 31, 2010, we had total consolidated debt of approximately $4.8 billion (including debt outstanding under our Credit Facility).  Our significant level of debt could:

 

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make it difficult to satisfy our financial obligations, including debt service requirements;

 

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limit our ability to obtain additional financing to operate our business;

 

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limit our financial flexibility in planning for and reacting to business and industry changes;

 

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impact the evaluation of our creditworthiness by counterparties to commercial agreements and affect their willingness to transact with us and/or the level of collateral we are required to post under such agreements;

 

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place us at a competitive disadvantage compared to less leveraged companies;

 

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increase our vulnerability to general adverse economic and industry conditions, including changes in interest rates and volatility in commodity prices; and

 

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require us to dedicate a substantial portion of our cash flows to principal and interest payments on our debt, thereby reducing the availability of our cash flow for other purposes including our operations, capital expenditures and future business opportunities.

 

Furthermore, we may incur or assume additional debt in the future.  If new debt is added to our current debt levels and those of our subsidiaries, the related risks that we and they face could increase significantly.

 

Our financing agreements governing our debt obligations require us to satisfy specific financial covenants.    Using the latest available forward commodity price curves and considering our current derivative contracts, we project that it is likely that we will not be able to comply with our EBITDA to Consolidated Interest Expense covenant, particularly in the third and fourth quarters of 2011.   Our failure to comply with the financial covenants w ould have a material adverse impact on our business, financial condition, results of operations and cash flows .  If we are unable to successfully execute our plan to amend or replace our Credit Facility or otherwise obtain additional sources of liquidity, it may be necessary for us to seek protection from creditors under Chapter 11 of the U.S. Bankruptcy Code, or an involuntary petition for bankruptcy may be filed against us.

 

Our financing agreements, including the Credit Facility, require us to meet specific financial covenants both as a matter of course and as a precondition to the incurrence of additional debt and to the making of restricted payments or asset sales, among other things.  Our obligations relating to ongoing financial covenants include the maintenance of specified financial ratios regarding Secured Debt to EBITDA and EBITDA to Consolidated Interest Expense (as each such term is defined in the Credit Facility) (together, the “Maintenance Covenants”).  The financial covenants set forth as a condition to the events described above include the demonstration, on a pro forma basis, of a specified ratio of Total Indebtedness to EBITDA (as each such term is defined in the Credit Facility).  Each of these three ratios becomes more restrictive over the course of 2011 and into 2012.

 

As of December 31, 2010, we were in compliance with the Maintenance Covenants.  Using the latest available forward commodity price curves and considering our current derivative contracts, we project that it is likely that we will not be able to comply with our EBITDA to Consolidated Interest Expense covenant, as currently set forth in our Credit Facility, particularly in the third and fourth quarters of 2011, which could result in an event of default causing our indebtedness thereunder (and any other indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions) to potentially become immediately due and payable.  If we are unable to cure or obtain a waiver for any such default, or are unable to obtain replacement financing or otherwise pay off such amounts, and our lenders accelerate the payment of such indebtedness, our lenders would be entitled to foreclose on, and acquire control of substantially all of our assets, which would have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

 

 

Item 1B.   Unresolved Staff Comments

Not applicable.

Item 2.   Properties

We have included descriptions of the location and general character of our principal physical operating properties by segment in “Item 1.  Business” for further discussion, which is incorporated herein by reference.  Substantially all of our assets, including the power generation facilities we own, are pledged as collateral to secure the repayment of, and our other obligations under, the Credit Facility.  Please read Note 18—Debt for further discussion.

Our principal executive office located in Houston, Texas is held under a lease that expires in December 2017.  We also lease additional offices or warehouses in the states of California, Colorado, Illinois, Indiana, New York, Pennsylvania and Texas.

Item 3.   Legal Proceedings

Please read Note 22—Commitments and Contingencies—Legal Proceedings for a description of our material legal proceedings, which is incorporated herein by reference.

 

 

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PART II

Item 5.   Market for Registrant ’ s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Dynegy

Dynegy’s common stock, $0.01 par value per share, is listed and traded on the New York Stock Exchange under the ticker symbol “DYN.”  The number of stockholders of record of its common stock as of March 3, 2011, based upon records of registered holders maintained by its transfer agent, was 11,763 .

On May 21, 2010, Dynegy’s stockholders approved a reverse stock split of outstanding common stock at a reverse ratio of 1-for-5.  This reverse stock split was effected on May 25, 2010.  The following table sets forth, for the fiscal periods indicated, the high and low closing sales prices for Dynegy’s common stock on the NYSE after giving effect to this reverse stock split (including for share prices prior to May 25, 2010), as reported on the New York Stock Exchange Composite Tape.

Summary of Dynegy’s Common Stock Price

		High				Low
2011:
First Quarter (through March 3, 2011)		$	6.29			$	5.57
2010:
Fourth Quarter		$	5.89			$	4.44
Third Quarter			5.10				2.78
Second Quarter			6.80				3.85
First Quarter			9.95				6.10
2009:
Fourth Quarter		$	13.15			$	9.05
Third Quarter			12.75				8.90
Second Quarter			12.35				7.25
First Quarter			13.45				5.20

During the fiscal years ended December 31, 2010 and 2009, Dynegy’s Board of Directors did not elect to pay a cash common stock dividend.  Please read “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Dividends on Dynegy Common Stock” for further discussion of its dividend policy and the impact of dividend restrictions contained in its financing agreements.  Dynegy has not paid a dividend on any class of its common stock since 2002.  Any decision to pay a dividend will be at the discretion of Dynegy’s Board of Directors, and subject to the terms of its then-outstanding indebtedness, but Dynegy does not expect to pay a dividend on its common stock in the foreseeable future.  Please read Note 23—Capital Stock—Common Stock for further discussion.

Stockholder Protection Rights Agreement.   On November 22, 2010, Dynegy’s Board of Directors adopted a Stockholder Protection Rights Plan (as subsequently amended, the “Rights Plan”) and declared a dividend of one stock purchase right (collectively, the “Rights”) for each share of common stock held by stockholders of record as of the close of business on December 2, 2010.

Dynegy’s Board of Directors adopted this short-term, narrowly tailored Rights Plan to prevent any person from obtaining control or de facto control of Dynegy without offering a control premium to all Dynegy stockholders.  The issuance of the Rights is not intended to prevent a sale of control of Dynegy that is determined by Dynegy’s Board of Directors to be fair, advisable and in the best interests of all Dynegy stockholders.  The Rights Plan provides that, unless terminated earlier by Dynegy, the Rights will expire following Dynegy’s next annual meeting of stockholders after the filing of the Form 10-K for the fiscal year 2010, unless the Rights Plan is approved by Dynegy’s stockholders (in which case it will expire at the first subsequent annual meeting at which it is not approved by a stockholder vote).

 

 

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Following distribution of the Rights, each Right will entitle its holder to purchase fractions of Participating Preferred Stock having economic and voting terms similar to those of one share of Dynegy’s common stock for an exercise price of $12.50 (subject to adjustment).

The Rights will be exercisable for shares of Dynegy common stock if Dynegy announces that a person or group has acquired 20 percent or more of Dynegy’s common stock or any person or group acquires more than 30 percent of Dynegy’s common stock.  Under the Rights Plan, synthetic ownership of Dynegy’s common stock in the form of certain derivative securities counts towards the 20 percent and 30 percent ownership thresholds, if Dynegy’s Board of Directors determines that the owner of such derivative securities is seeking to use the existence of such securities for the purpose or effect of changing or influencing control of Dynegy.

The Rights Plan also exempts from its provisions all-cash, fully financed offers for all outstanding shares of Dynegy’s common stock that provide for a per share price in excess of $5.00 and meet certain other requirements.  If the Rights become exercisable for Dynegy’s common stock, all Rights holders (other than the person or group triggering the Rights) will be entitled to purchase Dynegy’s common stock at a 50 percent discount.  For example, if at the time the Rights become exercisable for Dynegy’s common stock the exercise price is still $12.50 and Dynegy’s common stock has a per share market value of $5, each Right would be exercisable for five shares of common stock ($25 of market value) at an exercise price of $12.50, (i.e., five shares of common stock at a 50 percent discount).  Rights held by the person or group triggering the Rights will become void and will not be exercisable.  If any person or group acquires between 10 percent and 50 percent of Dynegy’s common stock, Dynegy’s Board of Directors may, at its option, cause the exchange of one share of Dynegy common stock for each Right.

The distribution of the Rights is not taxable to stockholders.  Until their distribution, the Rights will trade with Dynegy’s common stock.  Dynegy’s Board of Directors may terminate the Rights Plan prior to the time the Rights are triggered.  Please read Note 23—Capital Stock—Stockholder Protection Rights Agreement for further discussion.

Shareholder Agreements.   In November 2009, as part of the transactions with LS Power, Dynegy and LS Power terminated a then-existing shareholder agreement and entered into a second shareholder agreement (the “New Shareholder Agreement”) which, among other things, generally restricts LS Power from increasing its ownership for a specified period up to 30 months.  The New Shareholder Agreement does not, however, include any of the special rights (such as Board rights, special approval rights or preemption rights) previously associated with LS Power’s ownership.

Stockholder Return Performance Presentation .   The graph below compares the cumulative 5-year total return of holders of Dynegy’s common stock with the cumulative total returns of the S&P Midcap 400 index, and a customized peer group. The peer group includes: Calpine Corp., NRG Energy Inc. and GenOn Energy.  The graph tracks the performance of a $100 investment in Dynegy’s common stock, the peer group, and the index (with the reinvestment of all dividends) from December 31, 2005 to December 31, 2010.

 

 

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		12/05				12/06				12/07				12/08				12/09				12/10
Dynegy Inc.			100.00				149.59				147.52				41.32				37.40				23.22
S&P Midcap 400			100.00				110.32				119.12				75.96				104.36				132.16
Peer Group			100.00				127.39				211.71				82.56				95.35				90.33

The stock price performance included in this graph is not necessarily indicative of future stock price performance.

The above stock price performance comparison and related discussion is not to be deemed incorporated by reference by any general statement incorporating by reference this Form 10-K into any filing under the Securities Act of 1933 or under the Securities Exchange Act of 1934, or otherwise, except to the extent that we specifically incorporate this stock price performance comparison and related discussion by reference, and is not otherwise deemed “filed” under the Acts.

 

 

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Unregistered Sales of Equity Securities and Use of Proceeds.   When restricted stock awarded by Dynegy becomes taxable compensation to employees, shares may be withheld to cover the employees’ withholding taxes.  Information on Dynegy’s purchases of equity securities by means of such share withholdings during the quarter follows:

Period		(a) Total Number of Shares Purchased				(b) Average Price Paid per Share				(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs				(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 to October 31, 2010			359			$	4.82				—				N/A
November 1 to November 30, 2010			—			$	—				—				N/A
December 1 to December 31, 2010			—			$	—				—				N/A
Total			359			$	4.82				—				N/A

These were the only repurchases of equity securities made by Dynegy during the three months ended December 31, 2010.  Dynegy does not have a stock repurchase program.

DHI

All of DHI’s outstanding equity securities are held by its parent, Dynegy.  There is no established trading market for such securities and they are not traded on any exchange.

Securities Authorized for Issuance Under Equity Compensation Plans

Please read Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—Dynegy for information regarding securities authorized for issuance under our equity compensation plans.

 

 

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Item 6.    Selected Financial Data

The selected financial information presented below was derived from, and is qualified by, reference to our Consolidated Financial Statements, including the notes thereto, contained elsewhere herein.  The selected financial information should be read in conjunction with the Consolidated Financial Statements and related notes and Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Dynegy’s Selected Financial Data

		Year Ended December 31,
		2010				2009				2008				2007				2006
		(in millions, except per share data)
Statement of Operations Data (1):
Revenues		$	2,323			$	2,468			$	3,324			$	2,918			$	1,758
Depreciation and amortization expense			(392	)			(335	)			(346	)			(306	)			(208	)
Goodwill impairment			—				(433	)			—				—				—
Impairment and other charges, exclusive of goodwill impairment shown separately above			(148	)			(538	)			—				—				(9	)
General and administrative expenses			(163	)			(159	)			(157	)			(203	)			(196	)
Operating income (loss)			(11	)			(834	)			744				576				220
Interest expense and debt extinguishment costs (2)			(363	)			(461	)			(427	)			(384	)			(631	)
Income tax (expense) benefit			197				315				(90	)			(140	)			116
Income (loss) from continuing operations			(235	)			(1,040	)			188				105				(242	)
Income (loss) from discontinued operations (3)			1				(222	)			(17	)			166				(92	)
Cumulative effect of change in accounting principles			—				—				—				—				1
Net income (loss)		$	(234	)		$	(1,262	)		$	171			$	271			$	(333	)
Net income (loss) attributable to Dynegy Inc. common stockholders			(234	)			(1,247	)			174				264				(342	)
Basic earnings (loss) per share from continuing operations attributable to Dynegy Inc. common stockholders		$	(1.96	)		$	(6.25	)		$	1.14			$	1.10			$	(2.72	)
Basic net income (loss) per share attributable to Dynegy Inc. common stockholders			(1.95	)			(7.60	)			1.04				1.75				(3.72	)
Diluted earnings (loss) per share from continuing operations attributable to Dynegy Inc. common stockholders		$	(1.96	)		$	(6.25	)		$	1.14			$	1.10			$	(2.72	)
Diluted net income (loss) per share attributable to Dynegy Inc. common stockholders			(1.95	)			(7.60	)			1.04				1.75				(3.72	)
Shares outstanding for basic EPS calculation			120				164				168				151				92
Shares outstanding for diluted EPS calculation			121				165				168				151				102
Cash dividends per common share		$	—			$	—			$	—			$	—			$	—
Cash Flow Data:
Net cash provided by (used in) operating activities		$	423			$	135			$	319			$	341			$	(194	)
Net cash provided by (used in) investing activities			(534	)			251				(102	)			(817	)			358
Net cash provided by (used in) financing activities			(69	)			(608	)			148				433				(1,342	)
Cash dividends or distributions to partners, net			—				—				—				—				(17	)
Capital expenditures, acquisitions and investments			(531	)			(594	)			(640	)			(504	)			(163	)

 

 

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		December 31,
		2010				2009				2008				2007				2006
		(in millions)
Balance Sheet Data (4):
Current assets		$	2,244			$	2,038			$	2,803			$	1,663			$	1,989
Current liabilities			1,565				1,847				1,702				999				1,166
Property and equipment, net			6,273				7,117				8,934				9,017				4,951
Total assets			10,013				10,953				14,213				13,221				7,537
Long-term debt (excluding current portion)			4,626				4,775				6,072				5,939				3,190
Notes payable and current portion of long-term debt			148				807				64				51				68
Capital leases not already included in long-term debt			—				4				4				5				6
Total equity			2,746				2,979				4,485				4,529				2,267

(1)

The merger with LS Power (April 2, 2007) was accounted for in accordance with the purchase method of accounting and the results of operations attributable to the acquired business is included in our financial statements and operating statistics beginning on the acquisition’s effective date for accounting purposes.

 

(2)	Includes $249 million of debt conversion costs for the twelve months ended December 31, 2006.

 

(3)	Discontinued operations include the results of operations from the following businesses:

 

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The Arlington Valley and Griffith power generation facilities (collectively, the Arizona power generation facilities”) (sold fourth quarter 2009);

 

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Bluegrass power generating facility (sold fourth quarter 2009);

 

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Heard County power generating facility (sold second quarter 2009);

 

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Calcasieu power generating facility (sold first quarter 2008); and

 

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CoGen Lyondell power generating facility (sold third quarter 2007).

 

(4)	The merger with LS Power (April 2, 2007) was accounted for under the purchase method of accounting.  Accordingly, the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated fair values as of the effective date of the transaction.

 

 

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Dynegy Holdings’ Selected Financial Data

		Year Ended December 31,
		2010				2009				2008				2007				2006
		(in millions, except per share data)
Statement of Operations Data (1):
Revenues		$	2,323			$	2,468			$	3,324			$	2,918			$	1,758
Depreciation and amortization expense			(392	)			(335	)			(346	)			(306	)			(208	)
Goodwill impairment			—				(433	)			—				—				—
Impairment and other charges, exclusive of goodwill impairment shown separately above			(148	)			(538	)			—				—				(9	)
General and administrative expenses			(158	)			(159	)			(157	)			(184	)			(193	)
Operating income (loss)			(6	)			(836	)			744				595				223
Interest expense and debt extinguishment costs (2)			(363	)			(461	)			(427	)			(384	)			(579	)
Income tax (expense) benefit			184				313				(138	)			(105	)			89
Income (loss) from continuing operations			(243	)			(1,046	)			222				165				(217	)
Income (loss) from discontinued operations (3)			1				(222	)			(17	)			166				(91	)
Net income (loss)		$	(242	)		$	(1,268	)		$	205			$	331			$	(308	)
Net income (loss) attributable to Dynegy Holdings Inc.		$	(242	)		$	(1,253	)		$	208			$	324			$	(308	)
Cash Flow Data:
Net cash provided by (used in) operating activities		$	423			$	152			$	319			$	368			$	(205	)
Net cash provided by (used in) investing activities			(520	)			790				(87	)			(688	)			357
Net cash provided by (used in) financing activities			(69	)			(1,193	)			146				369				(1,235	)
Capital expenditures, acquisitions and investments			(517	)			(596	)			(626	)			(350	)			(155	)

		December 31,
		2010				2009				2008				2007				2006
		(in millions)
Balance Sheet Data (1):
Current assets		$	2,180			$	1,988			$	2,780			$	1,614			$	1,828
Current liabilities			1,562				1,848				1,681				999				1,165
Property and equipment, net			6,273				7,117				8,934				9,017				4,951
Total assets			9,949				10,903				14,174				13,107				8,136
Long-term debt (excluding current portion)			4,626				4,775				6,072				5,939				3,190
Notes payable and current portion of long-term debt			148				807				64				51				68
Capital leases not already included in long-term debt			—				4				4				5				6
Total equity			2,719				3,003				4,583				4,620				3,036

(1)

The LS Power assets were contributed to DHI contemporaneously with the merger with LS Power (April 2, 2007).  This contribution was accounted for as a transaction between entities under common control.  As such, the assets and liabilities were recorded by DHI at Dynegy’s historical cost on Dynegy’s date of acquisition.  Additionally, the Sithe Energies assets were contributed to DHI on April 2, 2007.  This contribution was accounted for as a transaction between entities under common control.  As such, the assets and liabilities were recorded by DHI at Dynegy’s historical cost on Dynegy’s date of acquisition, January 31, 2005.  In addition, DHI’s historical financial statements have been adjusted in all periods presented to reflect the contribution as though DHI had owned these assets beginning January 31, 2005.

 

(2)	Includes $204 million of debt conversion costs for the twelve months ended December 31, 2006.

 

(3)	Discontinued operations include the results of operations from the following businesses:

 

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The Arizona power generation facilities (sold fourth quarter 2009);

 

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Bluegrass power generating facility (sold fourth quarter 2009);

 

 

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Heard County power generating facility (sold second quarter 2009);

 

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Calcasieu power generating facility (sold first quarter 2008); and

 

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CoGen Lyondell power generating facility (sold third quarter 2007).

Item 7.   Management ’ s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read together with the audited consolidated financial statements and the notes thereto included in this report.

OVERVIEW

We are holding companies and conduct substantially all of our business operations through our subsidiaries.  Our current business operations are focused primarily on the power generation sector of the energy industry.  We report the results of our power generation business as three separate segments in our consolidated financial statements: (i) GEN-MW; (ii) GEN-WE; and (iii) GEN-NE.  Because of the diversity among their respective operations and how we allocate our resources, we report the results of each business as a separate segment in our consolidated financial statements.  Our consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.  Our investment in PPEA Holding Company, which was sold in the fourth quarter 2010, is included in GEN-MW for reporting purposes.

Going Concern.   Our accompanying consolidated financial statements have been prepared assuming that we will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these consolidated financial statements. However, continued low power prices over the past two years have had a significant adverse impact on our business.  Further, as our credit rating has declined, counterparty requirements for posting collateral in support of our risk management positions have become more stringent.  Over the next twelve months, we expect that we will continue to need to utilize our Credit Facility, through the issuance of letters of credit and/or through the drawing of cash, or secure additional sources of capital to continue to meet our operating needs.  The agreements governing our existing Credit Facility require us to meet specific financial covenants both as a matter of course and as a precondition to the incurrence of additional debt and to the making of restricted payments or asset sales, among other things.  These specific financial covenants are required to be calculated on a quarterly basis and become more restrictive over the course of 2011.  Using the latest available forward commodity price curves and considering our current derivative contracts, we project that it is likely that we will not be able to comply with our EBITDA to Consolidated Interest Expense covenant as currently set forth in our Credit Facility, particularly in the third and fourth quarters of 2011.  Furthermore, we expect that our available liquidity will continue to be reduced as a result of borrowing limitations under the covenant regarding the ratio of Secured Debt to EBITDA, as defined in our Credit Facility.  To continue as a going concern over the next twelve months, we must either (i) meet the financial covenants so that we can access our Credit Facility, or (ii) amend or replace our Credit Facility or otherwise secure additional capital.

At December 31, 2010, we have the following obligations outstanding under the Credit Facility:

 

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$68 million due April 2013 under the Term Loan B;

 

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$850 million due April 2013 under the Term Facility (fully collateralized by $850 million of non-current restricted cash); and

 

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$375 million in issued letters of credit.

A failure by us to comply with our financial covenants or to comply with the other restrictions in our financing agreements could result in reduced borrowing capacity or even a default, causing our debt obligations under such financing agreements (and any other indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions) to potentially become immediately due and payable.  If we are unable to cure any such default, or obtain a waiver or replacement financing, and those lenders accelerate the payment of such indebtedness, in the case that we are unable to repay those amounts, the holders of the indebtedness under our secured debt obligations would be entitled to foreclose on, and acquire control of substantially all of our assets, which would have a material adverse impact on our financial condition, results of operations and cash flows.

 

 

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In light of our likely covenant non-compliance, we are attempting to amend or replace our existing Credit Facility.  We expect the capacity of any amended or new credit facility to be less than the current capacity of $1.8 billion and to be at a higher cost.  We may also seek additional sources of liquidity in an effort to secure sufficient cash to meet our operating needs.  These additional sources of liquidity could include asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination of these.  H owever, we cannot provide any assurances that we will be successful in accomplishing any of these plans.

Our ability to continue as a going concern is dependent on many factors, including, among other things, our ability to achieve the operating results necessary to comply with the covenants in our existing Credit Facility, amend or replace our existing Credit Facility, or achieve the operating results necessary to comply with the covenants in any amended or new credit facility.  Such compliance will be dependent on our ability to successfully execute our commercial strategies, manage our collateral requirements, and continue to execute the company-wide cost reduction initiatives that are ongoing.

Recent transactions.   Beginning in 2010 and extending through January 2011, we engaged in an ongoing review of our operating and strategic opportunities and risks.  That review was conducted against a backdrop of continuing declines in the market prices of natural gas and wholesale electricity.  These declines have reduced the outlook for the cash flow that can be expected to be generated by us in the next several years.  Our declining cash flow, combined with our high level of indebtedness and the probable need to incur additional indebtedness to fund operations and required environmental capital expenditures led us to conclude that the risks of pursing a standalone business strategy are considerable.

On August 13, 2010, Dynegy entered into a merger agreement with an affiliate of The Blackstone Group L.P. (as amended, the “Blackstone Merger Agreement”), pursuant to which Dynegy would be acquired and Dynegy’s stockholders would receive $4.50 per share in cash.  On November 16, 2010, the agreement was amended to increase the merger consideration to $5.00 per share in cash.  The Blackstone Merger Agreement was not approved by Dynegy’s stockholders at a special stockholders’ meeting on November 23, 2010 and was subsequently terminated by the parties in accordance with the terms of the agreement.  The Blackstone Merger Agreement requires Dynegy to pay Blackstone a termination fee in the amount of approximately $16 million in the event that within 18 months of November 23, 2010, Dynegy consummates an alternative transaction having an aggregate value of more than $4.50 per share.

On November 23, 2010, we commenced the solicitation of transaction proposals from a broad group of potentially interested parties, including Icahn Enterprises L.P. (“Icahn”) and other potential strategic and financial buyers.  As a result of those efforts, on December 15, 2010, Dynegy’s Board of Directors unanimously approved a merger agreement between Dynegy and an affiliate of Icahn (as amended, the “Icahn Merger Agreement”).  In connection with the Icahn Merger Agreement, Icahn launched a cash tender offer on December 22, 2010 for all of the issued and outstanding shares of common stock at $5.50 per share (the “Tender Offer”).  On January 25, 2011, Dynegy announced that it did not receive any bona fide acquisition proposals.  At the expiration time of the Tender Offer on February 18, 2011, an insufficient number of shares had been tendered in response to the Tender Offer, and as a result the Icahn Merger Agreement automatically terminated.   In connection with the termination and as required by the Icahn Merger Agreement, in February 2011, Dynegy paid $5 million to Icahn with respect to expenses incurred by Icahn related to the Icahn Merger Agreement, and we may be required to pay additional fees of $11 million in the event that within 18 months of February 18, 2011, Dynegy consummates an alternative transaction having an aggregate value of more than $5.50 per share.

 

 

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Business Discussion

The following is a brief discussion of each of our power generation segments, including a list of key factors that have affected, and are expected to continue to affect, their respective earnings and cash flows.  We also present a brief discussion of our corporate-level expenses.

Power Generation Business

We generate earnings and cash flows in the three segments within our power generation business through sales of electric energy, capacity and ancillary services.  Primary factors affecting our earnings and cash flows in the power generation business include:

 

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Prices for power, natural gas, coal and fuel oil, which in turn are largely driven by supply and demand.  Demand for power can vary due to weather and general economic conditions, among other things.  For example, a warm summer or a cold winter typically increases demand for electricity.  Conversely, the recent recessionary economic environment has negatively impacted demand for electricity, and the proliferation of advanced shale gas drilling has increased domestic natural gas supplies, suppressing natural gas prices.  Power supplies similarly vary by region and are impacted significantly by available generating capacity, transmission capacity and federal and state regulation;

 

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The relationship between electricity prices and prices for natural gas and coal, commonly referred to as the “spark spread” and “dark spread”, respectively, which impacts the margin we earn on the electricity we generate; and

 

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Our ability to enter into commercial transactions to mitigate short- and medium- term earnings volatility and our ability to manage our liquidity requirements resulting from potential changes in collateral requirements as prices move.

Other factors that have affected, and are expected to continue to affect, earnings and cash flows for this business include:

 

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Transmission constraints, congestion, and other factors that can affect the price differential between the locations where we deliver generated power and the liquid market hub;

 

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Our ability to control capital expenditures, which primarily include maintenance, safety, environmental and reliability projects, and to control operating expenses through disciplined management;

 

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Our ability to optimize our assets by maintaining a high in-market availability, reliable run-time and safe, low-cost operations;

 

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Our ability to operate and market our facilities during periods of planned/unplanned electric transmission outages;

 

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Our ability to post the collateral necessary to execute our commercial strategy;

 

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The cost of compliance with existing and future environmental requirements that are likely to be more stringent and more comprehensive (please see Item 1. Business—Environmental Matters for further discussion); and

 

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Market supply conditions resulting from federal and regional renewable power mandates and initiatives.

 

 

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Please read Item 1A. Risk Factors for additional factors that could affect our future operating results, financial condition and cash flows.

In addition to these overarching factors, other factors have influenced, and are expected to continue to influence, earnings and cash flows for our three reportable segments within the power generation business as further described below.

Power Generation—Midwest Segment.   Our assets in GEN-MW include coal-fired facilities and natural gas-fired facilities.  The following specific factors affect or could affect the performance of this reportable segment:

 

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Our ability to maintain sufficient coal inventories, which is dependent upon the continued performance of the railroads for deliveries of coal in a consistent and timely manner, and its impact on our ability to serve the critical winter and summer on-peak loads;

 

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Our requirement to utilize a significant amount of cash for capital expenditures required to comply with the Midwest Consent Decree;

 

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Regional renewable energy mandates and initiatives that may alter supply conditions within the ISO and our generating units’ positions in the aggregate supply stack;

 

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Changes in the MISO market design or associated rules; and

 

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Changes in the existing PJM RPM capacity markets or in the bilateral MISO capacity markets and any resulting effect on future capacity revenues.

Power Generation—West Segment.   Our assets in GEN-WE are all natural gas-fired power generating facilities with the exception of our fuel oil-fired Oakland facility.  The following specific factors impact or could impact the performance of this reportable segment:

 

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Our ability to maintain and operate our plants in a manner that ensures we receive full capacity payments under our various tolling agreements;

 

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Our ability to maintain the necessary permits to continue to operate our Moss Landing and Morro Bay facilities with once-through, seawater cooling systems; and

 

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The cost incurred to demolish and remediate the South Bay facility.

Power Generation—Northeast Segment.   Our assets in GEN-NE include natural gas, fuel oil and coal-fired power generating facilities.  The following specific factors impact or could impact the performance of this reportable segment:

 

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Our ability to maintain sufficient coal and fuel oil inventories, including continued deliveries of coal and oil in a consistent and timely manner, and continued access to uninterrupted natural gas supplies, to serve the winter and summer on-peak loads;

 

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The additional costs imposed by state-driven environmental compliance initiatives aimed at reducing mercury emission levels and other constituents such as CO 2 ,   NO x and SO 2 as well as more restrictive measures for cooling water intakes for fish protection;

 

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Changes in NYISO/ISO-NE market rules or state-specific mandates that favor and/or subsidize renewable energy sources and demand response initiatives; and

 

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Our ability to preserve and/or capture value around planned transmission upgrades designed to improve transfer limits around known constraints.

 

 

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Other

Other includes corporate expenses such as general and administrative and interest.  Significant items impacting future earnings and cash flows include:

 

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Interest expense, which reflects debt with a weighted-average interest rate of approximately seven percent;

 

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General and administrative costs, which will be impacted by, among other things, (i) staffing levels and associated expenses; (ii) funding requirements under our pension plans; (iii) any future corporate-level litigation reserves or settlements and (iv) our ability to realize planned cost savings reflected in our financial forecasts; and

 

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Income taxes, which will be impacted by our ability to realize our net operating losses and alternative minimum tax credits.

Other also includes our legacy CRM operations, which primarily consists of a minimal number of legacy natural gas trading positions that will remain until 2017.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In this section, we describe our liquidity and capital requirements including our sources and uses of liquidity and capital resources.  Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, collateral requirements, fixed capacity payments and contractual obligations, capital expenditures (including required environmental expenditures) and working capital needs.  Examples of working capital needs include purchases and sales of commodities and associated margin and collateral requirements, facility maintenance costs and other costs such as payroll.

Our primary sources of internal liquidity are cash flows from operations, cash on hand, short-term investments and available capacity under our Credit Facility, of which the revolver capacity of $1,080 million is scheduled to mature in April 2012 and the term letter of credit capacity of $850 million is scheduled to mature in April 2013.

Our cash on hand and short-term investments as of December 31, 2010 and our internal forecasted cash flows from operations for 2011 are not expected to be sufficient to fund our planned $265 million 2011 capital expenditure program and our $148 million 2011 debt service requirements.  Furthermore, using the latest available forward commodity price curves and considering our current derivative contracts, we project that it is likely that we will not be able to comply with our EBITDA to Consolidated Interest Expense covenant contained in our Credit Facility, particularly in the third and fourth quarters of 2011.  Accordingly, as described at Going Concern above, we are attempting to amend or replace our existing Credit Facility.

We may also seek additional sources of liquidity in an effort to secure sufficient cash to meet our operating needs.  These additional sources of liquidity could include asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination of these.  Please read Capital Structuring Transactions and Asset Dispositions below for more detail.  H owever, we cannot provide any assurances that we will be successful in accomplishing any of these plans.

Please read the discussion above regarding Going Concern, as well as the discussion below regarding our Revolver Capacity, and Note 18 Debt—Credit Facility for a further discussion of the financial covenants contained in the Credit Facility.  For additional discussion of factors that may affect our ability to continue as a going concern and the potential consequences of our failure to do so, please see Item 1A—Risk Factors.

 

 

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Current Liquidity.   The following table summarizes our consolidated revolver capacity and liquidity position at March 3, 2011, December 31, 2010 and December 31, 2009:

 

		March 3, 2011				December 31, 2010				December 31, 2009
		(in millions)
Revolver capacity (1) (2)		$	954			$	954			$	1,080
Borrowings against revolver capacity			—				—				—
Term letter of credit capacity, net of required reserves		825					825				825
Plum Point and Sandy Creek letter of credit capacity (3)		—					—				102
Available contingent letter of credit facility capacity (4)		—					—				—
Outstanding letters of credit (3)		(392		)			(375	)			(536	)
Unused capacity		1,387					1,404				1,471
Cash—DHI		319					253				419
Short-term investments—DHI (5)		74					90				—
Total available liquidity—DHI		1,780					1,747				1,890
Cash—Dynegy		46					38				52
Short-term investments—Dynegy (5)		9					16				—
Total available liquidity—Dynegy		$	1,835			$	1,801			$	1,942

 

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(1)

We currently have a syndicate of lenders participating in the revolving portion of our Credit Facility with commitments ranging from $30 million to $165 million.

(2)

As of March 3, 2011 and December 31, 2010, DHI’s available liquidity under the Credit Facility was reduced by $126 million as a result of borrowing limitations under the covenant regarding the ratio of Secured Debt to EBITDA.  Although our available liquidity is reduced, we have adequate liquidity to meet expected needs for the remainder of the first quarter.  Further reduction in capacity may occur based on our ratio of Secured Debt to EBITDA at March 31, 2011, June 30, 2011, September 30, 2011 and December 31, 2011.  Please see Revolver Capacity below for further discussion.  Additionally, using the latest available forward commodity price curves and considering our current derivative contracts, we project that it is likely that we will not be able to comply with our EBITDA to Consolidated Interest Expense covenant, as defined in our Credit Facility, particularly in the third and fourth quarters of 2011.

(3)

Reflects reduction of $102 million of capacity as of January 1, 2010 due to the deconsolidation of PPEA Holding and the subsequent sale of our interest in PPEA Holding .  Please read Note 2—Summary of Significant Accounting Policies—Accounting Policies Adopted—Variable Interest Entities for further discussion.

(4)

Under the terms of the Contingent LC Facility, up to $150 million of capacity can become available, contingent on changes in forward spark spreads and power prices for 2012.

(5)

We invest our available cash balances in certain investments permitted by our internal policies and external financing agreements.  Please read Note 2—Summary of Significant Accounting Policies—Short-Term Investments and Note 6—Investments for further discussion.

 

Cash on Hand.   At March 3, 2011 and December 31, 2010, Dynegy had cash on hand of $365 million and $291 million, respectively, as compared to $471 million at the end of 2009. The increase in cash on hand at March 3, 2011 compared with December 31, 2010 is primarily related to the expiration of an agreement and the subsequent release of $50 million of restricted cash.  The decrease in cash on hand at December 31, 2010 as compared to the end of 2009 is primarily attributable to cash used for purchases of short-term investments, debt service and capital expenditures partially offset by cash generated from the operating activities of our power generation business.

 

 

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At March 3, 2011 and December 31, 2010, DHI had cash on hand of $319 million and $253 million, respectively, as compared to $419 million at the end of 2009.  The increase in cash on hand at March 3, 2011 compared with December 31, 2010 is primarily related to the expiration of an agreement and the subsequent release of $50 million of restricted cash.  The decrease in cash on hand at December 31, 2010 as compared to the end of 2009 is primarily attributable to cash used for purchases of short-term investments, debt service and capital expenditures partially offset by cash generated from the operating activities of our power generation business.

 

Revolver Capacity .   DHI’s available liquidity under the Credit Facility was reduced by $126 million as of December 31, 2010 as a result of borrowing limitations under the covenant regarding the ratio of Secured Debt to EBITDA (as defined therein).  The effect of reduced availability under the Credit Facility is less available liquidity to DHI.  Further reduction in capacity is likely to occur at March 31, 2011, June 30, 2011, September 30, 2011 and December 31, 2011.  Additionally, as discussed in Going Concern above, using the latest available forward commodity price curves and considering our current derivative contracts, we project that it is likely that we will not be able to comply with our EBITDA to Consolidated Interest Expense covenant, as currently set forth in our Credit Facility, particularly in the third and fourth quarters of 2011.  In such event, the Credit Facility may be terminated by the lenders and outstanding amounts thereunder accelerated.  Accordingly, we are attempting to amend or replace our existing Credit Facility.  Please read Going Concern above, Financial Covenants below and Note 18—Debt—Credit Facility for further discussion of our Credit Facility.

 

Capital-Structuring Transactions .   In light of our probable covenant non-compliance, we are attempting to amend or replace our existing Credit Facility.  We may also seek additional sources of liquidity in order to ensure that we have sufficient cash available to meet our operating needs.  These additional sources of liquidity could include asset sales, public or private issuances of debt, equity or  equity-linked securities,, debt for equity swaps,  or any combination of these.  Matters to be considered include depressed or dilutive prices for assets, cash interest expense, covenant compliance and maturity profile, all to be balanced with an attempt to maintain adequate liquidity.  The receptiveness of the traditional capital markets to an offering of debt or equity securities cannot be assured and may be negatively impacted by, among other things, the going concern emphasis paragraph in our most recent audit report, recent changes to our senior management and Dynegy’s Board of Directors, our non-investment grade credit ratings, significant debt maturities, business prospects and other factors beyond our control, including current and projected market conditions.  Any issuance of equity by Dynegy likely would have other effects as well, including stockholder dilution, and our ability to issue debt securities may be limited by our financing agreements, including our Credit Facility.

 

Operating Activities

 

Historical Operating Cash Flows.   Dynegy’s and DHI’s cash flow provided by operations totaled $423 million for the twelve months ended December 31, 2010.  During the period, our power generation business provided positive cash flow from operations of $938 million from the operation of our power generation facilities, primarily reflecting positive earnings for the period and approximately $290 million of cash received from our futures clearing manager.  The receipt of this cash is partly due to lower commodity prices and a reduction of margin requirements; the remaining cash was returned as a result of the posting of $85 million of short-term investments in substitute of cash.  Corporate and other operations included a use of cash of approximately $515 million by Dynegy and DHI, primarily due to interest payments to service debt and general and administrative expenses.

 

Dynegy’s cash flow provided by operations totaled $135 million for the twelve months ended December 31, 2009.  DHI’s cash flow provided by operations totaled $152 million for the twelve months ended December 31, 2009.  During the period, our power generation business provided positive cash flow from operations of $719 million.  Cash provided by the operations of our power generation facilities was partly offset by a $173 million increase in cash collateral postings.  Other included a use of cash of approximately $584 million and $567 million by Dynegy and DHI, respectively, primarily due to interest payments to service debt and general and administrative expenses.  Dynegy’s operating cash flow also reflected the payment of $19 million to LS Power in conjunction with the dissolution of DLS Power Holdings and DLS Power Development.

 

 

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Dynegy’s and DHI’s cash flow provided by operations totaled $319 million for the twelve months ended December 31, 2008.  During the period, our power generation business provided positive cash flow from the operations of our power generation facilities of $869 million, reflecting positive earnings for the period, partly offset by additional collateral requirements due to an increase in the volume of our hedging positions and increased payments associated with our DNE leveraged lease.  Please read Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations— Liquidity and Capital Resources—Off-Balance Sheet Arrangements—DNE Leveraged Lease for further discussion of the DNE lease payments.  Other included a use of approximately $550 million in cash primarily due to interest payments to service debt, general and administrative expenses and a $17 million legal settlement payment, partially offset by interest income.

 

Future Operating Cash Flows.   Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of power, the price of natural gas and its correlation to power prices, the cost of coal and fuel oil, collateral requirements, the value of capacity and ancillary services, the run time of our generating facilities, the effectiveness of our commercial strategy, legal, environmental and regulatory requirements, our ability to achieve the cost savings contemplated in our cost reduction programs and the level of our ability to capture value associated with commodity price volatility.  Given current forward commodity price curves, our future operating cash flows are likely to be insufficient to fund our planned capital expenditure program and our debt service requirements.

 

Collateral Postings.   We use a significant portion of our capital resources, in the form of cash, short-term investments and letters of credit, to satisfy counterparty collateral demands.  These counterparty collateral demands reflect our non-investment grade credit ratings and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.  At December 31, 2010, we had approximately $ 75 million of our cash collateral postings and $ 57 million of our letter of credit collateral postings related to our hedging activities. The following table summarizes our consolidated collateral postings to third parties by line of business at March 3, 2011, December 31, 2010 and December 31, 2009:

		March 3, 2011			December 31, 2010			December 31, 2009
		(in millions)
By Business :
Generation business		$	459		$	377		$	638
Other (1)			85			85			189
Total		$	544		$	462		$	827
By Type :
Cash and short-term investments (2)		$	152		$	87		$	291
Letters of credit			392			375			536
Total		$	544		$	462		$	827

 

(1)

March 3, 2011 and December 31, 2010 reflect the reduction of $102 million of capacity and corresponding outstanding letters of credit due to the deconsolidation and subsequent sale of our interest in PPEA Holding.  Please read Note 2—Summary of Significant Accounting Policies—Accounting Policies Adopted—Variable Interest Entities for further discussion.

(2)

Includes Broker margin account on our consolidated balance sheets as well as other collateral postings included in Prepayments and other current assets on our consolidated balance sheets .

 

 

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The change in letters of credit postings from December 31, 2009 to December 31, 2010 and to March 3, 2011 are primarily related to a $102 million decrease due to the removal of the PPEA letter of credit as a result of the deconsolidation and subsequent sale of our interest in PPEA Holding and lower commodity prices.  Collateral postings of cash and short-term investments also decreased from December 31, 2009 to December 31, 2010 due to lower commodity prices and a reduction of margin requirements during 2010.  Collateral postings increased from December 31, 2010 to March 3, 2011 due to an increase in margin requirements in 2011.

 

In addition to cash and letters of credit posted as collateral, we have granted additional permitted first priority liens on the assets currently subject to first priority liens under our Credit Facility as collateral under certain of our commodity derivative agreements in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements.  The counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under the Credit Facility.  The fair value of our commodity derivatives collateralized by first priority liens, netted by counterparty, included liabilities of $ 20 million, $30 million and $31 million at March 3, 2011, December 31, 2010 and December 31, 2009, respectively.

 

Going forward, we expect counterparties’ collateral demands to continue to reflect changes in commodity prices, including seasonal changes in weather-related demand, as well as their views of our creditworthiness.  If we do not have access to our Credit Facility or another borrowing facility, it will be difficult for us to satisfy counterparties’ collateral demands, including those for which no collateral is currently posted.  For further discussion, see Going Concern above.  Furthermore, our ability to use forward economic hedging instruments could be limited, due to the collateral requirements the use of such instruments entails.  If our commercial strategy is adjusted to reduce such collateral needs, we would be exposed to future increases and decreases in commodity prices and be limited in our ability to capture the extrinsic value associated with our portfolio of assets.

 

Investing Activities

 

Capital Expenditures.   We continue to tightly manage our operating costs and capital expenditures.  We had approximately $333 million, $612 million and $611 million in capital expenditures during the twelve months ended December 31, 2010, 2009 and 2008, respectively.  Our capital spending by reportable segment was as follows:

 

		December 31,
		2010				2009				2008
		(in millions)
GEN-MW		$	300			$	533			$	530
GEN-WE			19				45				29
GEN-NE			8				28				36
Other			6				6				16
Total		$	333			$	612			$	611

 

Capital spending in our GEN-MW segment primarily consisted of environmental and maintenance capital projects, as well as approximately $104 million and $203 million spent on development capital related to the Plum Point Project during the years ended December 31, 2009 and 2008, respectively.  Capital spending in our GEN-WE and GEN-NE segments primarily consisted of maintenance projects.

 

We expect capital expenditures for 2011 to approximate $265 million, which is comprised of $213 million, $14 million, $35 million and $3 million in GEN-MW, GEN-WE, GEN-NE and Other, respectively.  The $213 million of spending planned for GEN-MW includes approximately $145 million of environmental expenditures, of which approximately $140 million is related to the Midwest Consent Decree, approximately $53 million is related to maintenance on our coal and natural gas facilities, and approximately $15 million is related to capitalized interest.  Other spending primarily includes maintenance capital projects and environmental projects.  The capital budget is subject to revision as opportunities arise or circumstances change.  Our ability to fund these capital expenditures is dependent on our access to sufficient liquidity; see Going Concern above.

 

 

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The Midwest Consent Decree was finalized in July 2005.  It prohibits us from operating certain of our power generating facilities after certain dates unless specified emission control equipment is installed.  Our long-term capital expenditures in the GEN-MW segment will be significantly impacted by the Midwest Consent Decree.  We anticipate our total costs associated with the Midwest Consent Decree projects, which we expect to incur through 2013, to be approximately $960 million, which includes approximately $730 million spent to date.  This estimate, which is broken down by year below, includes a number of assumptions about uncertainties that are beyond our control.  For instance, we have assumed for purposes of this estimate that labor and material costs will increase at four percent per year over the remaining project term.  The following are the estimated remaining capital expenditures required to comply with the Midwest Consent Decree:

 

2011				2012				2013
				(in millions)
$	140			$	80			$	10

 

If the costs of these capital expenditures become great enough to render the operation of the affected facility or facilities uneconomical, we could, at our option, cease to operate the facility or facilities and forego these capital expenditures without incurring any further obligations under the Midwest Consent Decree.  Further, if we fail to meet certain performance standards under the Midwest Consent Decree our production may be affected  Please read Note 22—Commitments and Contingencies—Other Commitments and Contingencies—Midwest Consent Decree for further discussion.

 

Please read Note 1 —Organization and Operations—Going Concern for further discussion.

 

The SPDES permits renewal application at our Roseton power generating facility and the NPDES permit at our Moss Landing power generating facility have been challenged by local environmental groups which contend the existing once-through water cooling systems currently in place should be replaced with closed-cycle cooling systems.  A decision to install a closed-cycle cooling system at the Roseton or Moss Landing facilities would be made on a case-by-case basis considering all relevant factors at such time, including any relevant costs or applicable remediation requirements.  If mandated installation of closed-cycle cooling systems at either of these facilities would result in a material capital expenditure that renders the operation of a plant uneconomical, we could, at our option, and subject to any applicable financing agreements or other obligations, reduce operations or cease to operate such facility and forego these capital expenditures.

 

Please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Disclosure of Contractual Obligations and Contingent Financial Commitments—Off-Balance Sheet Arrangements—DNE Leveraged Lease for further discussion of early lease termination payments.  Please read Note 22—Commitments and Contingencies—Legal Proceedings—Roseton State Pollutant Discharge Elimination System Permit, and —Commitments and Contingencies—Legal Proceedings—Moss Landing National Pollutant Discharge Elimination System Permit for further discussion.

 

Asset Dispositions.   Proceeds from asset sales in 2009 totaled $652 million and $1,095 million for Dynegy and DHI, respectively.  Of the total $936 million and $1,476 million in cash proceeds received by Dynegy and DHI, respectively, at the closing of the LS Power Transactions, $547 million and $990 million related to the disposition of assets, including our interest in the Sandy Creek Project, for Dynegy and DHI, respectively.  We also received $175 million from the release of restricted cash on our consolidated balance sheets that was used to support our funding commitment to the Sandy Creek Project.  Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions—LS Power Transactions for further information.  The remaining $214 million of cash received upon closing the LS Power Transactions relates to the issuance of $235 million of notes payable, and is included in Financing Activities.  Please read “—Financing Activities” below and Note 19—Related Party Transactions for further discussion.

 

Additionally, during 2009, we sold the Heard County power generation facility for approximately $105 million, net of transaction costs.  Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Heard County for further discussion.

 

 

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Proceeds from asset sales in 2008 totaled $451 million, net of transaction costs, related to the sales of the Rolling Hills power generating facility, Calcasieu power generating facility, the NYMEX shares and seats, and the beneficial interest in Oyster Creek.

 

Consistent with industry practice, we regularly evaluate our generation fleet based primarily on geographic location, fuel supply, market structure, market recovery expectations, regulatory or legislative risks and cash flows.  We consider divestitures of assets where the balance of the above factors suggests that such assets’ earnings potential is limited or that the benefits that can be captured through a divestiture outweigh the benefits of continuing to own and operate such assets.  As future operating cash flows are likely to be insufficient to fund our planned capital expenditure program, lease obligations and our debt service requirements, additional asset divestures will be considered to supplement our liquidity position, potentially at terms not favorable to us.

 

Other Investing Activities.   Cash inflows related to short-term investments during the year ended December 31, 2010 totaled $326 million and $310 million for Dynegy and DHI, respectively, reflecting maturities and early redemptions of short-term investments.  Cash outflows related to purchases of short-term investments during the year ended December 31, 2010 totaled $508 million and $477 million for Dynegy and DHI, respectively.

 

Cash inflows related to short-term investments during the year ended December 31, 2009 totaled $17 million and $16 million for Dynegy and DHI, respectively, reflecting a distribution from our short-term investments.  Cash outflows related to short-term investments during the year ended December 31, 2008 totaled $27 million and $25 million for Dynegy and DHI, respectively, as a result of a reclassification from cash equivalents to short-term investments.

 

Dynegy made $16 million in contributions to DLS Power Holdings during the year ended December 31, 2008.  We received a distribution of approximately $7 million and repayment of approximately $3 million of an affiliate receivable upon the sale of a partial interest in Sandy Creek during the year ended December 31, 2008.  Please read Note 15—Variable Interest Entities—Sandy Creek for further discussion.

 

There was a $15 million cash outflow related to our funding commitment obligation under the PPEA Sponsor Support Agreement and a $3 million cash outflow due to changes in restricted cash balances during the year ended December 31, 2010 for both Dynegy and DHI.  There was a $190 million cash inflow during the year ended December 31, 2009 for both Dynegy and DHI, related to changes in restricted cash balances primarily due to the release of $175 million of restricted cash that was used to support our funding commitment to the Sandy Creek Project.  There was an $80 million cash inflow during the year ended December 31, 2008 due to changes in restricted cash balances primarily due to a reduction of our cash collateral as a result of SCEA’s sale of an 11 percent undivided interest in the Sandy Creek Project, the release of restricted cash and the use of restricted cash for the ongoing construction of the Plum Point project, partially offset by interest income.

 

DHI’s affiliate transactions during the year ended December 31, 2010 included $2 million.  DHI’s affiliate transactions during the year ended December 31, 2009 included $97 million related to the LS Power Transactions.  Dynegy repurchased 245 million of its Class B shares with a fair value of $443 million (based on a share price of $9.05 on November 30, 2009, as adjusted for the 1-for-5 reverse stock split of Dynegy’s common stock that became effective on May 25, 2010) from LS Power by exchanging assets owned by DHI for the shares.  In order to effect this exchange, Dynegy paid $540 million in cash to a subsidiary of LS Power in exchange for the shares, immediately following which a separate subsidiary of LS Power paid $540 million of cash to DHI in exchange for the assets.  The $97 million represents the difference between the $540 million of cash received by DHI and the $443 million fair value of the shares received by Dynegy.

 

Other included $3 million and $7 million of insurance proceeds received during the years ended December 31, 2009 and 2008, respectively.  Additionally, included in Other for Dynegy for the year ended December 31, 2008 is $4 million of proceeds from the liquidation of an investment.

 

 

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Financing Activities

 

Historical Cash Flow from Financing Activities.   Dynegy’s and DHI’s net cash used in financing activities during the twelve months ended December 31, 2010 totaled $69 million due to the payments of $62 million in aggregate principal amount on our Sithe 9.00 percent secured bonds due 2013 and $6 million of financing fees.

 

Dynegy’s net cash used in financing activities during the twelve months ended December 31, 2009 totaled $608 million.  Repayments of borrowings were $890 million, and consisted of the following:

 

●

$421 million in aggregate principal amount on our 6.875 percent senior unsecured notes due 2011 (“2011 Notes”);

 

●

$412 million in aggregate principal amount on our 8.75 percent senior unsecured notes due 2012 (“2012 Notes”); and

 

●

$57 million in aggregate principal amount on our Sithe 9.00 percent secured bonds due 2013.

 

We also paid debt extinguishment costs of $46 million in connection with the repayment of the 2011 Notes and 2012 Notes.

 

These payments were partially offset by $328 million of net proceeds from the following borrowings:

 

●

$130 million under the PPEA Credit Agreement Facility; and

 

●

$214 million of cash proceeds from the LS Power Transactions allocated to the issuance of $235 million 7.5 percent senior unsecured notes due 2015.

 

These borrowings were partly offset by $16 million of financing fees related to the Credit Facility Amendment No. 4.

 

DHI’s net cash used in financing activities during the twelve months ended December 31, 2009 totaled $1,193 million.  This included the net $608 million used in repayments and extinguishment costs, net of borrowings, incurred by Dynegy, as set forth above, as well as $585 million in aggregate dividend payments to Dynegy.

 

Dynegy’s net cash provided by financing activities during the twelve months ended December 31, 2008 totaled $148 million and  DHI’s net cash provided by financing activities during the twelve months ended December 31, 2008 totaled $146 million.  The cash provided by financing activities primarily related to $192 million of proceeds from borrowings under the PPEA Credit Agreement Facility, partly offset by a $45 million principal payment on our 9.00 percent Sithe secured bonds due 2013.

 

 

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Summarized Debt and Other Obligations.   The following table depicts our consolidated third party debt obligations, including the present value of the DNE leveraged lease payments discounted at 10 percent, and the extent to which they are secured as of December 31, 2010 and 2009:

		December 31, 2010				December 31, 2009
		(in millions)
First secured obligations		$	918			$	918
Unsecured obligations			3,644				3,645
Lease obligations (1)			590				626
Total corporate obligations			5,152				5,189
PPEA and Sithe secured non-recourse obligations (2)			225				1,031
Total obligations			5,377				6,220
Less: Lease obligations (1)			(590	)			(626	)
Other (3)			(13	)			(12	)
Total notes payable and long-term debt (4)		$	4,774			$	5,582

 

---

(1)

Represents present value of future lease payments associated with the DNE lease financing discounted at 10 percent.

(2)

Includes PPEA’s non-recourse project financing of $644 million and tax-exempt bonds of $100 million as of December 31, 2009.  Reflects reduction of $744 million as of January 1, 2010 due to the deconsolidation and subsequent sale of our interest in PPEA Holding.  Please read Note 2—Summary of Significant Accounting Policies—Accounting Policies Adopted—Variable Interest Entities for further discussion.

(3)

Consists of net discounts on debt of $13 million and $12 million at December 31, 2010 and 2009, respectively.

(4)

Does not include letters of credit.

 

Please read Note 18—Debt for further discussion of these items.  Our debt maturity profile as of December 31, 2010 includes $148 million in 2011, $164 million in 2012, $1,002 million in 2013, zero in 2014, $772 million in 2015 and approximately $2,688 million thereafter.  Maturities for 2011 represent principal payments on our Senior Unsecured Notes due 2011 and the Sithe Senior Notes.

 

Financing Trigger Events.   Our debt instruments and other financial obligations include provisions which, if not met, could require early payment, additional collateral support or similar actions.  These trigger events include the violation of financial covenants, including the Interest Coverage Ratio discussed below (and any other indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions), insolvency events, defaults on scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions.  We do not have any trigger events tied to specified Dynegy or DHI credit ratings or Dynegy’s stock price in our debt instruments and are not party to any contracts that require us to issue equity based on credit ratings or other trigger events.

 

 

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Financial Covenants. Our Credit Facility contains certain financial covenants, including (i) a covenant (measured as of the last day of the relevant fiscal quarter) that requires DHI and certain of its subsidiaries to maintain a ratio of Secured Debt to EBITDA (each as defined therein) for DHI and its relevant subsidiaries of no greater than a specified amount; and (ii) a covenant that requires DHI and certain of its subsidiaries to maintain a ratio of EBITDA to Consolidated Interest Expense (each as defined therein) for DHI and its relevant subsidiaries as of the last day of the measurement periods as specified below of no less than a specified amount.  The following table summarizes the required ratios:

 

Period Ended:		(i) Secured Debt: EBITDA		(ii) EBITDA: Consolidated Interest Expense
		No greater than:		No less than:
December 31, 2010		3.50 : 1		1.30 : 1
March 31, 2011		3.50 : 1		1.35 : 1
June 30, 2011		3.50 : 1		1.40 : 1
September 30, 2011		3.25 : 1		1.60 : 1
December 31, 2011		3.00 : 1		1.60 : 1
Thereafter		2.50 : 1		1.75 : 1

 

We are in compliance with these covenants as of December 31, 2010.

 

As of December 31, 2010, DHI’s available liquidity under the Credit Facility was reduced by $126 million as a result of borrowing limitations under the covenant regarding the ratio of Secured Debt to EBITDA.  Further reduction in capacity is likely to occur based on our ratio of Secured Debt to EBITDA at March 31, 2011, June 30, 2011, September 30, 2011 and December 31, 2011 based on our current projections.  Please see Going Concern and Revolver Capacity above for further discussion.

 

Using the latest available forward commodity price curves and considering our current hedging contracts, we project that it is likely that we will not be able to comply with the EBITDA to Consolidated Interest Expense covenant contained in our Credit Facility, particularly in the third and fourth quarters of 2011.  Please see Going Concern above for further discussion.

 

Subject to certain exceptions, DHI and its relevant subsidiaries are subject to restrictions on asset sales, incurring additional indebtedness, limitations on investments and certain limitations on dividends and other payments with respect to capital stock.  Please read Note 18—Debt—Credit Facility for further discussion of our amended Credit Facility.

 

For additional discussion of factors that may affect our ability to continue as a going concern and the potential consequences  of our failure to do so, please see Item 1A—Risk Factors.

 

Dividends on Dynegy Common Stock.   Dividend payments on Dynegy’s common stock are at the discretion of its Board of Directors and subject to limits contained in our Credit Facility and applicable law.  Dynegy did not declare or pay a cash dividend on its common stock for the year ended December 31, 2010 and it does not expect to pay a dividend on its common stock in the foreseeable future.

 

Credit Ratings

 

Our credit rating status is currently “non-investment grade”; our senior unsecured debt is rated “CCC” by Standard & Poor’s, “Caa2” by Moody’s, and “CCC” by Fitch.  On March 1, 2011, Standard & Poor’s downgraded our corporate family ratings to “CCC” from “B-” based on near-term risk of covenant default under the Credit Facility and the recently announced Board of Directors and management restructuring.  The agency also reduced our senior secured bank facilities rating to “B-” from “B+”, and senior unsecured debt rating to “CCC” from “B-”, while removing all ratings from credit watch with negative implications. The Standard & Poor's rating outlook is negative. On October 1, 2010, Moody’s issued a rating action to conclude their prior review.  The corporate family rating was downgraded to “Caa1”; the senior secured rating downgraded to “B1”; and the senior unsecured rating was confirmed at “Caa2.” The Moody's rating outlook is negative. On November 24, 2010, Fitch removed the ratings watch and downgraded the issuer default rating for Dynegy Inc. and Dynegy Holdings Inc. to “CCC” from “B-”; reduced our senior secured bank facilities to “B+” from “BB-”; and reduced our senior unsecured debt to “CCC” from “B”.  The Fitch rating outlook remains negative.  The downgrades did not trigger any obligations under our financing arrangements; however, as a result of the March 1, 2011 Standard & Poor's downgrade, we have received demands to post additional collateral in support of certain of our operational agreements in 2011.

 

 

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Disclosure of Contractual Obligations and Contingent Financial Commitments

 

We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities.  Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements.  These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.  Contingent financial commitments represent obligations that become payable only if certain pre-defined events occur, such as financial guarantees.  Details on these obligations are set forth below.

 

Contractual Obligations

 

The following table summarizes our contractual obligations as of December 31, 2010.  Cash obligations reflected are not discounted and do not include accretion or dividends.

 

		Expiration by Period
		Total				Less than 1 Year				1 – 3 Years				3 - 5 Years				More than 5 Years
		(in millions)
Long-term debt (including current portion)		$	4,774			$	148			$	1,166			$	772			$	2,688
Interest payments on debt			1,798				357				635				514				292
Operating leases			925				138				363				305				119
Coal commitments (1)			647				215				262				170				—
Capacity payments			156				35				68				47				6
Interconnection obligations			17				1				2				2				12
Construction service agreements			314				56				79				101				78
Pension funding obligations			53				12				41				—				—
Other obligations			87				26				29				21				11
Total contractual obligations		$	8,771			$	988			$	2,645			$	1,932			$	3,206

 

---

(1)

Included based on nature of purchase obligations under associated contracts.

 

Long-Term Debt (Including Current Portion).   Total amounts of Long-term debt (including current portion) are included in the December 31, 2010 consolidated balance sheet.  Please read Note 18—Debt for further discussion.

 

Interest Payments on Debt.   Interest payments on debt represent periodic interest payment obligations associated with our long-term debt (including current portion).  Please read Note 18—Debt for further discussion.

 

Operating Leases.   Operating leases includes the minimum lease payment obligations associated with our DNE leveraged lease.  Please read “—Liquidity and Capital Resources—Off-Balance Sheet Arrangements—DNE Leveraged Lease” for further discussion.  Amounts also include minimum lease payment obligations associated with office and office equipment leases.

 

In addition, we are party to two charter party agreements relating to two VLGCs previously utilized in our former global liquids business.  The aggregate minimum base commitments of the charter party agreements are approximately $14 million each year for the years 2011 through 2012, and approximately $17 million in aggregate for the period from 2013 through lease expiration.  The charter party rates payable under the two charter party agreements vary in accordance with market-based rates for similar shipping services.  The $14 million and $17 million amounts set forth above are based on the minimum obligations set forth in the two charter party agreements.  The primary terms of the charter party agreements expire September 2013 and September 2014, respectively.  We have sub-chartered both VLGCs to a wholly owned subsidiary of Transammonia Inc.  The terms of the sub-charters are identical to the terms of the original charter agreements.  We continue to rely on the sub-charters with a subsidiary of Transammonia to satisfy the obligations of our two charter party agreements.  To date, the subsidiary of Transammonia has complied with the terms of the sub-charter agreements.

 

 

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Coal Commitments.   At December 31, 2010, we had contracts in place to purchase coal for various of our generation facilities with minimum commitments of $647 million.  Obligations related to the purchase of coal are $636 million through 2015, and obligations related to the transportation are   $11 million through 2013.

 

Capacity Payments.   Capacity payments include fixed obligations associated with transmission, transportation and storage arrangements totaling approximately $156 million.

 

Interconnection Obligations .   Interconnection obligations represent an obligation with respect to interconnection services for our Ontelaunee facility.  This agreement expires in 2027.  Our obligation under this agreement is approximately $1 million per year through the term of the contract.

 

Construction Service Agreements.   Construction service agreements represent obligations with respect to long-term plant maintenance agreements.  Our obligation under these agreements is approximately $314 million.

 

Pension Funding Obligations.   Amounts include estimated defined benefit pension funding obligations for 2011—$12 million, 2012—$23 million and 2013—$18 million.  Although we expect to continue to incur funding obligations subsequent to 2013, we cannot confidently estimate the amount of such obligations at this time and, therefore, have not included them in the table above.  Please read Note 24—Employee Compensation, Savings and Pension Plans—Pension and Other Post-Retirement Benefits—Obligations and Funded Status for further discussion.

 

Other Obligations.   Other obligations primarily include the following items:

 

●

Demolition and restoration obligation associated with our South Bay facility of $40 million;

 

●

Payments associated with a capacity contract between Independence and Con Edison.  The aggregate payments through the 2014 expiration are approximately $8 million as of December 31, 2010;

 

●

Reserve of $5 million for expenses payable to Icahn associated with the termination of the Icahn Merger Agreement;

 

●

Reserves of $5 million recorded in connection with uncertain tax positions.  Please read Note 20—Income Taxes—Unrecognized Tax Benefits for further discussion; and

 

●

Severance reserves of $15 million accrued in connection with a reduction in workforce and the closure of certain power generation facilities.  Of this amount, $12 million of expense was recorded in 2010.  Please read Note 7—Impairment and Restructuring Charges—Restructuring Charges for further discussion.

 

 

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Contingent Financial Obligations

 

The following table provides a summary of our contingent financial obligations as of December 31, 2010 on an undiscounted basis.  These obligations represent contingent obligations that may require a payment of cash upon the occurrence of specified events.

 

		Expiration by Period
		Total				Less than 1 Year				1–3 Years				3-5 Years				More than 5 Years
		(in millions)
Letters of credit (1)		$	375			$	375			$	—			$	—			$	—
Breakup Fees (2)			27				27				—				—				—
Surety bonds (3)			5				5				—				—				—
Guarantees			2				1				1				—				—
Total financial commitments		$	409			$	408			$	1			$	—			$	—

 

---

(1)

Amounts include outstanding letters of credit.

(2)

The Breakup Fees represent contractual obligations to pay $16 million to The Blackstone Group and $11 million to Icahn under certain circumstances.  Please read Note 22—Commitments and Contingencies for further discussion.

(3)

Surety bonds are generally on a rolling 12-month basis.  The $5 million of surety bonds are primarily supported by collateral.

 

Off-Balance Sheet Arrangements

 

DNE Leveraged Lease.   In May 2001, we entered into an asset-backed sale-leaseback transaction to provide us with long-term financing for our acquisition of certain power generating facilities.  In this transaction, which was structured as a sale-leaseback to minimize our operating cost of the facilities on an after-tax basis and to transfer ownership to the purchaser, we sold four of the six generating units comprising the facilities to Danskammer OL LLC and Roseton OL LLC, each of which was newly formed by an unrelated third party investor, for approximately $920 million and we concurrently agreed to lease them back from these entities, which we refer to as the owner lessors.  The owner lessors used $138 million in equity funding from the unrelated third party investor to fund a portion of the purchase of the respective facilities.  The remaining $800 million of the purchase price and the related transaction expenses were derived from proceeds obtained in a private offering of pass-through trust certificates issued by two of our subsidiaries, Dynegy Danskammer, L.L.C. and Dynegy Roseton, L.L.C., which serve as lessees of the applicable facilities.  The pass-through trust certificate structure was employed, as it has been in similar financings historically executed in the airline and energy industries, to optimize the cost of financing the assets and to facilitate a capital markets offering of sufficient size to enable the purchase of the lessor notes from the owner lessors.  The pass-through trust certificates were sold to qualified institutional buyers in a private offering and the proceeds were used to purchase debt instruments, referred to as lessor notes, from the owner lessors.  The pass-through trust certificates and the lessor notes are held by pass-through trusts for the benefit of the certificate holders.  The lease payments on the facilities support the principal and interest payments on the pass-through trust certificates, which are ultimately secured by a mortgage on the underlying facilities.

 

As of December 31, 2010, future lease payments are $112 million for 2011, $179 million for 2012, $142 million for 2013, $143 million for 2014, $143 million for 2015 and $105 million in the aggregate due from 2016 through lease expiration.  The Roseton lease expires on February 8, 2035 and the Danskammer lease expires on May 8, 2031.  We have no option to purchase the leased facilities at the end of their respective lease terms.  DHI has guaranteed the lessees’ payment and performance obligations under their respective leases on a senior unsecured basis.  At December 31, 2010, the present value (discounted at 10 percent) of future lease payments was $590 million.

 

 

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The following table sets forth our lease expenses and lease payments relating to these facilities for the periods presented:

 

		2010				2009				2008
		(in millions)
Lease Expense		$	50			$	50			$	50
Lease Payments (Cash Flows)		$	95			$	141			$	144

 

If one or more of the leases were to be terminated because of an event of loss, because it had become illegal for the applicable lessee to comply with the lease or because a change in law had made the facility economically or technologically obsolete, DHI would be required to make a termination payment in an amount sufficient to compensate the lessor for termination of the lease, including redeeming the pass-through trust certificates related to the unit or facility for which the lease was terminated at par plus accrued and unpaid interest.  As of December 31, 2010, the termination payment at par would be approximately $816 million for all of the leased facilities.  If a termination of this type were to occur with respect to all of the leased facilities, it would be difficult for DHI to raise sufficient funds to make this termination payment.  Alternatively, if one or more of the leases were to be terminated because we determine, for reasons other than as a result of a change in law, that it has become economically or technologically obsolete or that it is no longer useful to our business, DHI must redeem the related pass-through trust certificates at par plus a make-whole premium in an amount equal to the discounted present value of the principal and interest payments still owing on the certificates being redeemed less the unpaid principal amount of such certificates at the time of redemption.  For this purpose, the discounted present value would be calculated using a discount rate equal to the yield-to-maturity on the most comparable U.S. Treasury security plus 50 basis points.  At December 31, 2010, we estimate that the make-whole premium for the remaining pass through certificates would be approximately $109 million.

 

Commitments and Contingencies

 

Please read Note 22—Commitments and Contingencies, which is incorporated herein by reference, for further discussion of our material commitments and contingencies.

 

 

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RESULTS OF OPERATIONS

 

Overview and Discussion of Comparability of Results.   In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the years ended December 31, 2010, 2009 and 2008.  At the end of this section, we have included our business outlook for each segment.

 

We report results of our power generation business as three separate geographical segments as follows: (i) GEN-MW, (ii) GEN-WE and (iii) GEN-NE.  Because of the diversity among their respective operations and how we allocate our resources, we report the results of each business as a separate segment in our consolidated financial statements.  Our consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.

 

Summary Financial Information-Dynegy.   The following tables provide summary financial data regarding Dynegy’s consolidated and segmented results of operations for 2010, 2009 and 2008, respectively.

 

Dynegy’s Results of Operations for the Year Ended December 31, 2010

		Power Generation
		GEN-MW				GEN-WE				GEN-NE				Other				Total
		(in millions)
Revenues		$	1,126			$	455			$	742			$	—			$	2,323
Cost of sales			(516	)			(179	)			(486	)			—				(1,181	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below			(202	)			(91	)			(155	)			(2	)			(450	)
Depreciation and amortization expense			(296	)			(66	)			(24	)			(6	)			(392	)
Impairment and other charges			(4	)			(1	)			(137	)			(6	)			(148	)
General and administrative expense			—				—				—				(163	)			(163	)
Operating income (loss)		$	108			$	118			$	(60	)		$	(177	)		$	(11	)
Losses from unconsolidated investments			(62	)			—				—				—				(62	)
Other items, net			1				—				1				2				4
Interest expense																			(363	)
Loss from continuing operations before income taxes																			(432	)
Income tax benefit																			197
Loss from continuing operations																			(235	)
Income from discontinued operations, net of taxes																			1
Net loss and net loss attributable to Dynegy Inc.																		$	(234	)

 

 

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Dynegy’s Results of Operations for the Year Ended December 31, 2009

		Power Generation
		GEN-MW				GEN-WE				GEN-NE				Other				Total
		(in millions)
Revenues		$	1,257			$	380			$	834			$	(3	)		$	2,468
Cost of sales			(505	)			(156	)			(534	)			1				(1,194	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below			(222	)			(120	)			(181	)			4				(519	)
Depreciation and amortization expense			(215	)			(62	)			(47	)			(11	)			(335	)
Goodwill impairments			(76	)			(260	)			(97	)			—				(433	)
Impairment and other charges, exclusive of goodwill impairments shown separately above			(147	)			—				(391	)			—				(538	)
Loss on sale of assets			(96	)			—				(28	)			—				(124	)
General and administrative expense			—				—				—				(159	)			(159	)
Operating loss		$	(4	)		$	(218	)		$	(444	)		$	(168	)		$	(834	)
Earnings (losses) from unconsolidated investments			—				(72	)			—				1				(71	)
Other items, net			2				3				1				5				11
Interest expense and debt extinguishment costs																			(461	)
Loss from continuing operations before income taxes																			(1,355	)
Income tax benefit																			315
Loss from continuing operations																			(1,040	)
Loss from discontinued operations, net of taxes																			(222	)
Net loss																			(1,262	)
Less:  Net loss attributable to the noncontrolling interests																			(15	)
Net loss attributable to Dynegy Inc.																		$	(1,247	)

 

 

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Dynegy’s Results of Operations for the Year Ended December 31, 2008

 

		Power Generation
		GEN-MW				GEN-WE				GEN-NE				Other				Total
		(in millions)
Revenues		$	1,621			$	702			$	1,006			$	(5	)		$	3,324
Cost of sales			(583	)			(415	)			(705	)			10				(1,693	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below			(203	)			(98	)			(180	)			15				(466	)
Depreciation and amortization expense			(205	)			(77	)			(54	)			(10	)			(346	)
Gain on sale of assets			56				11				—				15				82
General and administrative expense			—				—				—				(157	)			(157	)
Operating income (loss)		$	686			$	123			$	67			$	(132	)		$	744
Losses from unconsolidated investments			—				(40	)			—				(83	)			(123	)
Other items, net			—				5				6				73				84
Interest expense																			(427	)
Income from continuing operations before income taxes																			278
Income tax expense																			(90	)
Income from continuing operations																			188
Loss from discontinued operations, net of taxes																			(17	)
Net income																			171
Less:  Net loss attributable to the noncontrolling interests																			(3	)
Net income attributable to Dynegy Inc.																		$	174

 

EBITDA and Adjusted EBITDA-Dynegy.    We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit), and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA adjusted for certain items described below and presented in the accompanying reconciliation.  Adjusted EBITDA is not a measure calculated in accordance with GAAP (a non-GAAP measure), and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with GAAP.  Our Credit Facility includes a similar measure as a basis for certain financial covenants.

 

We believe that Adjusted EBITDA provides a meaningful representation of our operating performance.  Adjusted EBITDA is meant to reflect the true operating performance of our power generation fleet; consequently, it excludes the impact of mark-to-market accounting and other items that could be considered “ non-operating ” or “ non-core ” in nature, and includes the contributions of those plants classified as discontinued operations.  Because Adjusted EBITDA is a financial measure that management uses to allocate resources, determine Dynegy ’ s ability to fund capital expenditures, assess performance against its peers and evaluate overall financial performance, we believe it provides useful information for our investors.  In addition, many analysts, fund managers and other stakeholders that communicate with us typically request our financial results in an Adjusted EBITDA format.

 

We believe that Adjusted EBITDA is only useful as an additional tool to help management and investors make informed decisions about Dynegy ’ s financial and operating performance.  By definition, non-GAAP measures do not give a full understanding of Dynegy; therefore, to be truly valuable, they must be used in conjunction with the GAAP measures.  Non-GAAP financial measures are not standardized; therefore, it may not be possible to compare Adjusted EBITDA with other companies ’ financial measures having the same or similar names.  We strongly encourage investors to review our consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

 

 

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We use these non-GAAP financial measures in addition to, and in conjunction with, results presented in accordance with GAAP.  These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed with our GAAP results and the accompanying reconciliations to corresponding GAAP financial measures included in our results of operations, may provide a more complete understanding of factors and trends affecting our business.  These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are by definition an incomplete understanding of Dynegy, and must be considered in conjunction with GAAP measures.

 

In summary, our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with Dynegy ’ s Board of Directors, stockholders, creditors, analysts and investors concerning our financial performance.

 

When Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to Adjusted EBITDA is net income (loss) attributable to Dynegy.  Further, because management does not allocate interest expense and income taxes on a segment level, the most directly comparable GAAP financial measure to Adjusted EBITDA when performance is discussed on a segment level or plant level is Operating income (loss).

 

The tables below provide a reconciliation of Adjusted EBITDA to our income (loss) from operations on a segment basis and to net income attributable to Dynegy on a consolidated basis for years ended December 31, 2010, 2009 and 2008, respectively.

 

Dynegy’s Adjusted EBITDA for the Year Ended December 31, 2010

		Power Generation
		GEN-MW				GEN-WE				GEN-NE				Other				Total
		(in millions)
Net loss and net loss attributable to Dynegy Inc.																		$	(234	)
Income tax benefit																			(197	)
Interest expense																			363
Losses from unconsolidated investments																			62
Income from discontinued operations, net of taxes																			(1	)
Other items, net																			(4	)
Operating income (loss)		$	108			$	118			$	(60	)		$	(177	)		$	(11	)
Depreciation and amortization expense			296				66				24				6				392
Losses from unconsolidated investments			(62	)			—				—				—				(62	)
Other items, net			1				—				1				2				4
EBITDA from continuing operations			343				184				(35	)			(169	)			323
EBITDA from discontinued operations			—				1				—				—				1
EBITDA			343				185				(35	)			(169	)			324
Impairments			37				—				136				—				173
Loss on sale of PPEA Holding			28				—				—				—				28
Merger Agreement transaction costs			—				—				—				26				26
Restructuring charges			4				1				1				6				12
Plum Point mark-to-market gains			(6	)			—				—				—				(6	)
Mark-to-market gains, net			12				(33	)			3				—				(18	)
Adjusted EBITDA		$	418			$	153			$	105			$	(137	)		$	539

 

 

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Dynegy’s Adjusted EBITDA for the Year Ended December 31, 2009

		Power Generation
		GEN-MW				GEN-WE				GEN-NE				Other				Total
		(in millions)
Net loss attributable to Dynegy Inc.																		$	(1,247	)
Income tax benefit																			(315	)
Interest expense																			461
Losses from unconsolidated investments																			71
Loss from discontinued operations, net of taxes																			222
Net loss attributable to noncontrolling interests																			(15	)
Other items, net																			(11	)
Operating loss		$	(4	)		$	(218	)		$	(444	)		$	(168	)		$	(834	)
Other items			2				3				1				5				11
Depreciation and amortization expense			215				62				47				11				335
Earnings (losses) from unconsolidated investments			—				(72	)			—				1				(71	)
Net loss attributable to noncontrolling interests			15				—				—				—				15
EBITDA from continuing operations			228				(225	)			(396	)			(151	)			(544	)
EBITDA from discontinued operations			(46	)			(282	)			—				—				(328	)
EBITDA			182				(507	)			(396	)			(151	)			(872	)
Goodwill impairments			76				260				97				—				433
Impairments and other charges (1)			170				235				391				—				796
Loss on LS Power Transactions			118				82				28				—				228
Gain on sale of Heard County (2)			—				(10	)			—				—				(10	)
Loss on sale of Sandy Creek			—				84				—				—				84
Sandy Creek mark-to-market gains			—				(21	)			—				—				(21	)
Mark-to-market losses, net			112				58				10				—				180
Net loss attributable to noncontrolling interests			(15	)			—				—				—				(15	)
Adjusted EBITDA		$	643			$	181			$	130			$	(151	)		$	803

 

---

(1)

Includes $235 million and $23 million of impairment charges related to our Arizona and Bluegrass power generation facilities, respectively, which are included in discontinued operations.

(2)

Included in discontinued operations.

 

 

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Dynegy’s Adjusted EBITDA for the Year Ended December 31, 2008

		Power Generation
		GEN-MW				GEN-WE				GEN-NE				Other				Total
		(in millions)
Net income attributable to Dynegy Inc.																		$	174
Income tax expense																			90
Interest expense																			427
Losses from unconsolidated investments																			123
Loss from discontinued operations, net of taxes																			17
Net loss attributable to noncontrolling interests																			(3	)
Other items, net																			(84	)
Operating income (loss)		$	686			$	123			$	67			$	(132	)		$	744
Depreciation and amortization expense			205				77				54				10				346
Losses from unconsolidated investments			—				(40	)			—				(83	)			(123	)
Other items			—				5				6				73				84
Net loss attributable to noncontrolling interests			3				—				—				—				3
EBITDA from continuing operations			894				165				127				(132	)			1,054
EBITDA from discontinued operations			(1	)			(9	)			—				4				(6	)
EBITDA			893				156				127				(128	)			1,048
Gain on sale of Rolling Hills			(56	)			—				—				—				(56	)
Impairment of equity investment			—				—				—				24				24
Loss on dissolution of equity investment			—				—				—				47				47
Asset impairments			—				47				—				—				47
Sandy Creek mark-to-market losses			—				40				—				—				40
Gain on liquidation of foreign entity			—				—				—				(24	)			(24	)
Release of state franchise tax and sales tax liabilities			—				—				—				(16	)			(16	)
Gain on sale of NYMEX shares			—				—				—				(15	)			(15	)
Gain on sale of Sandy Creek ownership interest			—				(13	)			—				—				(13	)
Gain on sale of Oyster Creek ownership interest			—				(11	)			—				—				(11	)
Mark-to-market gains, net			(191	)			(51	)			(11	)			—				(253	)
Adjusted EBITDA		$	646			$	168			$	116			$	(112	)		$	818

 

 

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Summary Financial Information-DHI.   The following tables provide summary financial data regarding DHI’s consolidated and segmented results of operations for 2010, 2009 and 2008, respectively.

 

DHI’s Results of Operations for the Year Ended December 31, 2010

 

		Power Generation
		GEN-MW				GEN-WE				GEN-NE				Other				Total
		(in millions)
Revenues		$	1,126			$	455			$	742			$	—			$	2,323
Cost of sales			(516	)			(179	)			(486	)			—				(1,181	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below			(202	)			(91	)			(155	)			(2	)			(450	)
Depreciation and amortization expense			(296	)			(66	)			(24	)			(6	)			(392	)
Impairment and other charges			(4	)			(1	)			(137	)			(6	)			(148	)
General and administrative expense			—				—				—				(158	)			(158	)
Operating income (loss)		$	108			$	118			$	(60	)		$	(172	)		$	(6	)
Losses from unconsolidated investments			(62	)			—				—				—				(62	)
Other items, net			1				—				1				2				4
Interest expense																			(363	)
Loss from continuing operations before income taxes																			(427	)
Income tax benefit																			184
Loss from continuing operations																			(243	)
Income from discontinued operations, net of taxes																			1
Net loss																		$	(242	)

 

 

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DHI’s Results of Operations for the Year Ended December 31, 2009

 

		Power Generation
		GEN-MW				GEN-WE				GEN-NE				Other				Total
		(in millions)
Revenues		$	1,257			$	380			$	834			$	(3	)		$	2,468
Cost of sales			(505	)			(156	)			(534	)			1				(1,194	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below			(222	)			(120	)			(181	)			2				(521	)
Depreciation and amortization expense			(215	)			(62	)			(47	)			(11	)			(335	)
Goodwill impairments			(76	)			(260	)			(97	)			—				(433	)
Impairment and other charges, exclusive of goodwill impairments shown separately above			(147	)			—				(391	)			—				(538	)
Loss on sale of assets			(96	)			—				(28	)			—				(124	)
General and administrative expense			—				—				—				(159	)			(159	)
Operating loss		$	(4	)		$	(218	)		$	(444	)		$	(170	)		$	(836	)
Losses from unconsolidated investments			—				(72	)			—				—				(72	)
Other items, net			2				3				1				4				10
Interest expense and debt extinguishment costs																			(461	)
Loss from continuing operations before income taxes																			(1,359	)
Income tax benefit																			313
Loss from continuing operations																			(1,046	)
Loss from discontinued operations, net of taxes																			(222	)
Net loss																			(1,268	)
Less: Net loss attributable to the noncontrolling interests																			(15	)
Net loss attributable to Dynegy Holdings Inc.																		$	(1,253	)

 

 

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DHI’s Results of Operations for the Year Ended December 31, 2008

 

		Power Generation
		GEN-MW				GEN-WE				GEN-NE				Other				Total
		(in millions)
Revenues		$	1,621			$	702			$	1,006			$	(5	)		$	3,324
Cost of sales			(583	)			(415	)			(705	)			10				(1,693	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below			(203	)			(98	)			(180	)			15				(466	)
Depreciation and amortization expense			(205	)			(77	)			(54	)			(10	)			(346	)
Gain on sale of assets			56				11				—				15				82
General and administrative expense			—				—				—				(157	)			(157	)
Operating income (loss)		$	686			$	123			$	67			$	(132	)		$	744
Losses from unconsolidated investments			—				(40	)			—				—				(40	)
Other items, net			—				5				6				72				83
Interest expense																			(427	)
Income from continuing operations before income taxes																			360
Income tax expense																			(138	)
Income from continuing operations																			222
Loss from discontinued operations, net of taxes																			(17	)
Net income																			205
Less: Net loss attributable to the noncontrolling interests																			(3	)
Net income attributable to Dynegy Holdings Inc.																		$	208

 

 

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The following table provides summary operating statistics by segment for the years ended December 31, 2010, 2009 and 2008, respectively:

 

		Year Ended December 31,
		2010				2009				2008
GEN-MW
Million Megawatt Hours Generated (1) (2)			26.4				24.9				24.4
In Market Availability for Coal Fired Facilities (3)			91	%			90	%			90	%
Average Capacity Factor for Combined Cycle Facilities (4)			26	%			29	%			16	%
Average Quoted On-Peak Market Power Prices ($/MWh) (5):
Cinergy (Cin Hub)		$	42			$	35			$	67
Commonwealth Edison (NI Hub)		$	41			$	35			$	66
PJM West		$	54			$	45			$	84
Average On-Peak Market Spark Spreads ($/MWh) (6):
PJM West		$	19			$	12			$	15
GEN-WE
Million Megawatt Hours Generated (7) (8)			4.0				5.6				8.6
Average Capacity Factor for Combined Cycle Facilities (4)			36	%			41	%			65	%
Average Quoted On-Peak Market Power Prices ($/MWh) (5):
North Path 15 (NP 15)		$	40			$	39			$	80
Average On-Peak Market Spark Spreads ($/MWh) (6):
North Path 15 (NP 15)		$	6			$	8			$	18
GEN-NE
Million Megawatt Hours Generated			8.3				10.2				7.9
In Market Availability for Coal Fired Facilities (3)			95	%			95	%			91	%
Average Capacity Factor for Combined Cycle Facilities (4)			47	%			44	%			25	%
Average Quoted On-Peak Market Power Prices ($/MWh) (5):
New York—Zone G		$	59			$	50			$	101
New York—Zone A		$	44			$	36			$	68
Mass Hub		$	56			$	46			$	91
Average On-Peak Market Spark Spreads ($/MWh) (6):
New York—Zone A		$	9			$	4			$	3
Mass Hub		$	18			$	12			$	23
Fuel Oil		$	(72	)		$	(53	)		$	(37	)
Average natural gas price—Henry Hub ($/MMBtu) (9)		$	4.38			$	3.92			$	8.85

 

---

(1)

Excludes less than 0.1 million MWh generated by our Bluegrass power generation facility, which we sold on November 30, 2009 and is reported in discontinued operations, for the years ended December 31, 2009 and 2008.

(2)

Includes 0.2 million MWh generated by our GEN-MW investment in the Plum Point power generation facility for the year ended December 31, 2010.  Our investment in this facility was sold on November 10, 2010.

(3)

Reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched.

(4)

Reflects actual production as a percentage of available capacity.  Excludes the Arizona power generation facilities which are reported as discontinued operations with respect to the GEN-WE segment.

(5)

Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

(6)

Reflects the simple average of the spark spread available to either a 7.0 MMBtu/MWh heat rate generator or an 11.0 MMBtu/MWh heat rate fuel oil-fired generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price and does not necessarily reflect spark spreads available to us.

 

 

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(7)

Includes 0.4 million MWh generated by our GEN-WE investment in the Black Mountain power generation facility for the years ended December 31, 2010, 2009 and 2008, respectively.

(8)

Excludes less than 0.1 million MWh generated by our Calcasieu and Heard County power generation facilities, which we sold on March 31, 2008 and April 30, 2009, respectively, and are reported in discontinued operations, for the years ended December 31, 2009 and 2008.  Excludes approximately 2.4 million MWh and 2.6 million MWh generated by our Arizona power generation facilities, which we sold on November  30, 2009 and is reported in discontinued operations, for the years ended December 31, 2009 and 2008, respectively.

(9)

Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by the Company.

 

The following tables summarize significant items on a pre-tax basis, with the exception of the tax items, affecting net income (loss) for the periods presented.

 

		Year Ended December 31, 2010
		Power Generation
		GEN-MW				GEN-WE				GEN-NE				Other				Total
		(in millions)
Impairments and other charges (1)		$	(41	)		$	(1	)		$	(137	)		$	(6	)		$	(185	)
Loss on sale of PPEA Holding (2)			(28	)			—				—				—				(28	)
Merger Agreement transaction costs (3)			—				—				—				(26	)			(26	)
Taxes (4)			—				—				—				20				20
Total—DHI			(69	)			(1	)			(137	)			(12	)			(219	)
Taxes (4)			—				—				—				10				10
Total—Dynegy		$	(69	)		$	(1	)		$	(137	)		$	(2	)		$	(209	)

 

---

(1)

Includes $37 million of impairment charges related to our equity investment in PPEA Holding, which is included in Losses from unconsolidated investments.  Also includes $134 million and $2 million of impairment charges related to our Casco Bay and Roseton/Danskammer power generation facilities, respectively and $12 million related to restructuring charges in connection with a reduction in workforce and the closure of certain power generation facilities.  These charges are included in Impairment and other charges on our consolidated statements of operations.

(2)

The loss on sale of our investment in PPEA Holding represents the recognition of $28 million in losses on interest rate swaps that were previously deferred in Accumulated other comprehensive loss.  These charges are included in Losses from unconsolidated investments on our consolidated statements of operations.

(3)

Includes $26 million of expenses in connection with our prior proposed merger with an affiliate of The Blackstone Group.  These expenses are included in General and Administrative expenses on our consolidated statements of operations.

(4)

Includes a benefit of $12 million for Dynegy and $8 million for DHI related to a change in California state tax law and a benefit of $18 million for Dynegy and $12 million for DHI related to the release of a reserve for uncertain tax positions as a result of completion of an audit, adjustments to tax positions related to prior years and various state settlements.

 

 

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		Year Ended December 31, 2009
		Power Generation
		GEN-MW				GEN-WE				GEN-NE				Other				Total
		(in millions)
Impairments (1)		$	(246	)		$	(495	)		$	(488	)		$	—			$	(1,229	)
Loss on extinguishment of debt (2)			—				—				—				(46	)			(46	)
Loss on LS Power Transactions (3)			(118	)			(82	)			(28	)			—				(228	)
Loss on sale of Sandy Creek Project (4)			—				(84	)			—				—				(84	)
Sandy Creek Project mark-to-market gains (5)			—				21				—				—				21
Gain on sale of Heard County (6)			—				10				—				—				10
Taxes (7)			—				—				—				(26	)			(26	)
Total—DHI			(364	)			(630	)			(516	)			(72	)			(1,582	)
Taxes (7)			—				—				—				(7	)			(7	)
Total—Dynegy		$	(364	)		$	(630	)		$	(516	)		$	(79	)		$	(1,589	)

 

---

(1)

Includes $235 million and $23 million of impairment charges related to our Arizona and Bluegrass power generation facilities, respectively, which are included in discontinued operations.

(2)

Related to debt extinguishment costs for repurchase of the 2011 Notes and the 2012 Notes during the fourth quarter 2009.

(3)

Includes $82 million and $22 million of losses related to our Arizona and Bluegrass power generation facilities, respectively, which are included in discontinued operations.

(4)

The loss on sale of Dynegy’s investment in the Sandy Creek Project to LS Power includes the recognition of $40 million in losses on interest rate swaps that were previously deferred in Accumulated other comprehensive loss on our consolidated balance sheets.  These charges are included in Losses from unconsolidated investments on our consolidated statements of operations.

(5)

These mark-to-market gains represent our 50 percent share prior to the sale.

(6)

Included in discontinued operations.

(7)

Includes charges of $21 million for Dynegy and $16 million for DHI related to a change in California state law and charges of $12 million for Dynegy and $10 million for DHI due to revised assumptions around our ability to use certain state deferred tax assets.

 

		Year Ended December 31, 2008
		Power Generation
		GEN-MW				GEN-WE				GEN-NE				Other				Total
		(in millions)
Gain on sale of Rolling Hills		$	56			$	—			$	—			$	—			$	56
Release of state franchise tax and sales tax liability			—				—				—				16				16
Gain on sale of NYMEX shares			—				—				—				15				15
Gain on sale of Oyster Creek ownership interest			—				11				—				—				11
Gain on sale of Sandy Creek Project ownership interest			—				13				—				—				13
Gain on liquidation of foreign entity			—				—				—				24				24
Sandy Creek Project mark-to-market losses (1)			—				(40	)			—				—				(40	)
Taxes (2)			—				—				—				12				12
Heard County impairment (3)			—				(47	)			—				—				(47	)
Total—DHI		$	56			$	(63	)		$	—			$	67			$	60
Impairment of equity investment			—				—				—				(24	)			(24	)
Loss on dissolution of equity investment			—				—				—				(47	)			(47	)
Taxes (2)			—				—				—				6				6
Total—Dynegy		$	56			$	(63	)		$	—			$	2			$	(5	)

 

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(1)

These mark-to-market losses represent our 50 percent share.

(2)

Represents the benefit of adjustments arising from the measurement of temporary differences.

(3)

Included in discontinued operations.

 

 

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Year Ended 2010 Compared to Year Ended 2009

 

Operating Income (Loss)

 

Operating loss for Dynegy was $11 million for the year ended December 31, 2010, compared to an operating loss of $834 million for the year ended December 31, 2009.  Operating loss for DHI was $6 million for the year ended December 31, 2010, compared to an operating loss of $836 million for the year ended December 31, 2009.

 

Our operating loss for the year ended December 31, 2010 includes a pre-tax asset impairment of $134 million related to our Casco Bay power generating facility and related assets and $2 million related to the asset impairment of our Roseton and Danskammer power generation facilities.  Our operating loss for the year ended December 31, 2009 was driven, in large part, by $538 million of asset impairments, a $433 million impairment of goodwill and a $124 million fourth quarter 2009 loss on the closing of the LS Power Transactions.  Please read Note 16—Goodwill for further discussion of the goodwill impairments, Note 7—Impairment and Restructuring Charges for further discussion of the asset impairments and Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions—LS Power Transactions for further discussion of the loss on the LS Power Transactions.

 

Mark-to-market gains (losses) on commodity derivative instruments associated with our generating assets are included in Revenues in the consolidated statements of operations.  Such gains totaled $21 million for the year ended December 31, 2010, compared to $180 million of mark-to-market losses for the year ended December 31, 2009.  The gains in 2010 reflect an increase in the value of positions due to decreasing forward market prices, partially offset by the impact of the settlement of risk management positions that matured during the year.  The losses in 2009 were a result of the impact of the settlement of risk management positions that matured during 2009, for which earnings were recognized in prior periods.

 

We do not designate our commodity derivative instruments as cash flow hedges for accounting purposes.  Please read Note 8—Risk Management Activities, Derivatives and Financial Instruments for further discussion.  The resulting mark-to-market accounting treatment results in the immediate recognition of gains and losses within revenues in the consolidated statements of operations due to changes in the fair value of the derivative instruments.  As a result, these mark-to-market gains and losses are not reflected in the consolidated statements of operations in the same period as the underlying power sales from generation activity for which the derivative instruments serve as economic hedges.  The expected cash impact of the settlement of our open positions (which amounted to a $34 million net asset at December 31, 2010) will be recognized over time largely through the end of 2011 and 2012 based on the prices at which such positions are contracted.  Our overall mark-to-market position and the related mark-to-market value will change as we buy or sell volumes within the forward market and as forward commodity prices fluctuate.

 

Power Generation—Midwest Segment.   Operating income for GEN-MW was $108 million for the year ended December 31, 2010, compared  to an operating loss of $4 million for the year ended December 31, 2009.  Operating income for the year ended December 31, 2009 included a pre-tax charge of approximately $76 million for the impairment of goodwill, reflected in Goodwill impairments in our consolidated statement of operations, and also included is a pre-tax charge of approximately $147 million for the impairments of the Renaissance, Riverside/Foothills, Rocky Road and Tilton power generating facilities and related assets, reflected in Impairment and other charges on our consolidated  statements of operations.  Please read Note 16—Goodwill for further discussion of the goodwill impairments and Note 7—Impairment and Restructuring Charges for further discussion of the asset impairments.  In addition, operating income for the year ended December 31, 2009 also included a $96 million pre-tax charge from the sale of our Renaissance, Riverside/Foothills, Rocky Road and Tilton power generating facilities to LS Power, reflected in Gain (loss) on sale of assets in our consolidated statements of operations.

 

 

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Revenues for the year ended December 31, 2010 decreased by $131 million compared to the year ended December 31, 2009, cost of sales increased by $11 million and operating and maintenance expense decreased by $20 million, resulting in a net decrease of $122 million.  The decrease was primarily driven by the following:

 

●

Energy sales – GEN-MW’s results from energy sales, including both physical and financial transactions, decreased from $701 million for the year ended December 31, 2009 to $483 million for the year ended December 31, 2010.  The contribution from physical transactions increased primarily as a result of higher power prices at our coal fired facilities and improved spark spreads at our combined cycle facilities, partially offset by more unplanned outages as well as the impact of a $50 million payment received for the year ended December 31, 2009 to assign our rights to a third party pursuant to a power sales agreement.  These increases were more than offset by reduced contribution from financial transactions; and

 

●

Decreased tolling/capacity revenues of $24 million – Tolling and capacity revenues decreased $38 million as a result of the sale of assets in the fourth quarter 2009 and another $27 million due to lower capacity prices in MISO.  These decreases were partially offset by $12 million due to the monetization and replacement, at a lower volume, of a tolling agreement on the Kendall facility and a $29 million increase attributable to higher PJM capacity prices and the additional capacity made available by the termination of the previous Kendall tolling agreement.

 

These items were partly offset by the following:

 

●

Reduced Mark-to-market losses – GEN-MW’s results for the year ended December 31, 2010 included mark-to-market losses of $12 million related to forward sales and other derivative contracts, compared to $112 million of mark-to-market losses for the year ended December 31, 2009.  The $12 million in 2010 mark-to-market losses reflects $68 million of losses related to positions that settled in 2010, largely offset by $56 million of gains related to positions that will settle in 2011 and beyond; and

 

●

Decreased operating and maintenance expenses – operating and maintenance expenses decreased from $222 million for the year ended December 31, 2009 to $202 million for the year ended December 31, 2010, primarily as a result of the sale of certain Midwest assets to LS Power in the fourth quarter 2009 as well as lower planned outage expenses.

 

Depreciation expense increased from $215 million for the year ended December 31, 2009 to $296 million for the year ended December 31, 2010, primarily as a result of accelerating the depreciation of our Vermilion facility, as we do not currently expect the facility to continue to operate beyond the first quarter 2011.  In addition, capital projects associated with the Midwest Consent Decree and early retirement of Wood River units 1-3 and Havana units 1-5 also increased depreciation expense.  This increase in depreciation was partly offset by the impact of the sale of certain Midwest assets to LS Power in 2009.

 

Power Generation—West Segment.   Operating income for GEN-WE was $118 million for the year ended December 31, 2010, compared to an operating loss of $218 million for the year ended December 31, 2009.  Operating loss for the year ended December 31, 2009 included a pre-tax charge of approximately $260 million for the impairment of goodwill, reflected in Goodwill impairments on our consolidated statements of operations.

 

Revenues for the year ended December 31, 2010 increased by $75 million compared to the year ended December 31, 2009, cost of sales increased  by $23 million and operating and maintenance expense decreased by $29 million, resulting in a net increase of $81 million.  The increase was primarily driven by the following:

 

●

Mark-to-market gains – GEN-WE’s results for the year ended December 31, 2010 included mark to-market gains of $30 million, compared to $58 million of mark-to-market losses for the year ended December 31, 2009.  Of the $30 million in 2010 mark-to-market gains, $5 million related to positions that settled in 2010, and the remaining $25 million related to positions that will settle in 2011 and beyond; and

   

 

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●

Decreased operating and maintenance expenses – operating and maintenance expenses decreased from $120 million for the year ended December 31, 2009 to $91 million for the year ended December 31, 2010, primarily as a result of planned outages at our Moss Landing facility in 2009, the retirement of two units at our South Bay facility in 2009 and lower maintenance expenses.

 

These items were partly offset by the following:

 

●

Energy sales – GEN-WE’s results from energy sales, including both physical and financial transactions, decreased from $100 million for the year ended December 31, 2009 to $81 million for the year ended December 31, 2010.  The contribution from physical transactions decreased primarily as a result of reduced spark spreads and forced outages.  The contribution from financial transactions also decreased; and

 

●

Decreased tolling/RMR revenues of $16 million – Tolling/RMR revenues decreased primarily as a result of  lower contracted prices and less contracted volumes for South Bay, Moss Landing unplanned outages and lower variable revenues.

 

Depreciation expense increased from $62 million for year ended December 31, 2009 to $66 million for the year ended December 31, 2010, as a result of capital projects placed into service.

 

Power Generation—Northeast Segment.   Operating loss for GEN-NE was $60 million for the year ended December 31, 2010, compared to an operating loss of $444 million for the year ended December 31, 2009.  Operating loss for the year ended December 31, 2010 includes pre-tax charges of approximately $134 million for the impairment of our Casco Bay facility and related assets and $2 million of impairment charges related to our Roseton/Danskammer power generation facilities which are reflected in Impairment and other charges in our consolidated statements of operations.  Operating loss for the year ended December 31, 2009 included a pre-tax charge of approximately $97 million for the impairment of goodwill reflected in Goodwill impairments in our consolidated statements of operations.  In 2009, we also recorded a pre-tax charge of approximately $179 million for the impairment of our Bridgeport power generating facility and related assets as well as a pre-tax charge of approximately $212 million for the impairment of our Roseton and Danskammer power generation facilities and related assets which are reflected in Impairment and other charges in our consolidated statements of operations.  Please read Note 7—Impairment  and Restructuring Charges for further discussion.  Operating loss for the year ended December 31, 2009 also included a $28 million pre-tax charge from the sale of our Bridgeport power generating facility to LS Power, reflected in Gain (loss) on sale of assets in our consolidated statements of operations.

 

Revenues for the year ended December 31, 2010 decreased by $92 million compared to the year ended December 31, 2009, cost of sales decreased by $48 million and operating and maintenance expense decreased by $26 million, resulting in a net decrease of $18 million.  The decrease was primarily driven by the following:

 

●

Energy sales  – GEN-NE’s results from energy sales, including both physical and financial transactions, decreased from $120 million for the year ended December 31, 2009 to $76 million for the year ended December 31, 2010.  The contribution from physical transactions increased primarily as a result of improved spark spreads and higher weather related prices; however, these increases were more than offset by the sale of the Bridgeport facility in the fourth quarter 2009, and reduced contribution from financial transactions;

 

●

Decreased capacity revenues of $23 million – Capacity revenues decreased primarily due to a $21 million reduction in capacity revenue from the Bridgeport facility that was sold to LS Power in the fourth quarter 2009.  This decrease was partially offset by increased capacity revenues at our other facilities due to slightly higher prices; and

 

●

Emissions sales – sales of emissions decreased by $10 million due to lower sale volumes and market prices of emissions credits in 2010.

 

 

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These items were partly offset by the following:

 

●

Mark-to-market gains – GEN-NE  results for the year ended December 31, 2010 included mark-to-market gains of $3 million related to forward sales, compared to mark-to-market losses of $10 million for the year ended December 31, 2009.  The $3 million in 2010 mark-to-market gains reflects $1 million of losses related to positions that settled in 2010 offset by $4 million of gains related to positions that will settle in 2011 and beyond;

 

●

Decreased operating and maintenance expenses – Operating and maintenance expenses decreased from $181 million for the year ended December 31, 2009 to $155 million for the year ended December 31, 2010 primarily as a result of the sale of the Bridgeport facility in the fourth quarter 2009 and lower maintenance expenses;

 

●

A coal inventory write-down of approximately $11 million recorded during the year ended December 31, 2009; and

 

●

An increase of $8 million related to an opportunistic sale of excess fuel oil from our Roseton facility in 2010.

 

Depreciation expense decreased from $47 million for the year ended December 31, 2009 to $24 million for the year ended December 31, 2010, primarily due to the 2009 sale of our Bridgeport power generating facility and the 2009 impairments of our Roseton and Danskammer power generation facilities.

 

Other.   Dynegy’s other operating loss for the year ended December 31, 2010 was $177 million, compared to an operating loss of $168 million for the year ended December 31, 2009.  DHI’s other operating loss for the year ended December 31, 2010 was $172 million, compared to an operating loss of $170 million for year ended December 31, 2009.  Operating losses in both periods were comprised primarily of general and administrative expenses.

 

Dynegy’s consolidated general and administrative expenses increased from $159 million from the year ended December 31, 2009 to $163 million for the year ended December 31, 2010.  DHI’s consolidated general and administrative expenses decreased from $159 million from the year ended December 31, 2009 to $158 million for the year ended December 31, 2010.

 

General and administrative expenses for the year ended December 31, 2010 include $26 million of Blackstone Merger Agreement and Icahn Merger Agreement costs and $9 million of legal expenses partially offset by reduced costs in 2010 associated with our company-wide cost savings programs compared with 2009.

 

Losses from Unconsolidated Investments

 

Dynegy’s and DHI’s losses from unconsolidated investments were $62 million related to our former GEN-MW investment in PPEA Holding Company.  The losses consisted of $28 million related to the loss on sale of PPEA Holding Company, sold in fourth quarter 2010, and an impairment charge of approximately $37 million partially offset by $3 million in equity earnings primarily related to mark-to-market gains on interest rate swaps offset by financing expenses. Our investment in PPEA Holding was fully impaired at March 31, 2010 due to the uncertainty regarding PPEA’s financing structure.

 

Dynegy’s and DHI’s losses from unconsolidated investments were $71 million and $72 million, respectively, for the year ended December 31, 2009.  The loss includes a loss of $84 million on the sale of our investment in the Sandy Creek Project to LS Power partially offset by equity earnings of $12 million.  Please read Note 4— Dispositions, Contract Terminations and Discontinued Operations—Dispositions—LS Power Transactions for further discussion.   In addition, Dynegy recorded $1 million of earnings related to its former investment in DLS Power Development, included in Other.

 

 

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Other Items, Net

 

Dynegy’s and DHI’s other items, net, totaled $4 million of income for December 31, 2010, compared to $11 million and $10 million, respectively, of income for the year ended December 31, 2009.  The decrease is primarily associated with insurance proceeds received in 2009 and with lower interest income due to lower cash and restricted cash balances in 2010.

 

Interest Expense

 

Dynegy’s and DHI’s interest expense and debt extinguishment costs totaled $363 million for the year ended December 31, 2010, compared to $461 million for the year ended December 31, 2009.  The decrease was primarily attributable to lower outstanding debt in 2010 and $46 million of debt extinguishment costs in 2009 due to the December 2009 repurchase of $833 million in aggregate principal amount of our senior unsecured notes as well as the deconsolidation and subsequent sale of our interest in PPEA Holding in 2010.  Please read Note 15—Variable Interest Entities—PPEA Holding Company LLC for further discussion.  These decreases were partly offset by the December 2009 issuance of $235 million of senior unsecured notes in connection with the LS Power Transactions and higher applicable margin on our variable-rate debt resulting from an amendment to the Credit Facility in August 2009.

 

Income Tax Benefit

 

Dynegy reported an income tax benefit from continuing operations of $197 million for the year ended December 31, 2010, compared to an income tax benefit from continuing operations of $315 million for the year ended December 31, 2009.  The 2010 effective tax rate was 46 percent, compared to 23 percent in 2009.

 

DHI reported an income tax benefit from continuing operations of $184 million for the year ended December 31, 2010, compared to an income tax benefit of $313 million from continuing operations for the year ended December 31, 2009.  The 2010 effective tax rate was 43 percent, compared to 23 percent in 2009.

 

The difference between the statutory rate of 35 percent and the effective rates of 46 percent and 43 percent for Dynegy and DHI, respectively, for the year ended December 31, 2010 resulted primarily from the benefit of $18 million and $12 million for Dynegy and DHI, respectively, resulting from the release of a reserve for uncertain tax positions upon completion of a federal income tax audit together with an overall state tax benefit resulting from current year losses, changes in our state sales profile and a benefit of $12 million and $8 million recorded by Dynegy and DHI, respectively, resulting from a change in California state tax law.

 

The difference between the statutory rate of 35 percent and the effective rate of 23 percent for Dynegy and DHI for the year ended December 31, 2009 resulted primarily from the effect of the non-deductible goodwill impairment charge, non-deductible losses from the LS Power Transactions and state income taxes in the taxing jurisdictions in which our assets operate.  The income tax benefit for the year ended December 31, 2009 included an overall state tax benefit resulting from current year losses, changes in our state sales profile, the exit from various states due to the LS Power Transactions, and charges of $21 million and $16 million recorded by Dynegy and DHI, respectively, resulting from a change in California state tax law.  We also revised our assumptions around the ability to utilize certain state deferred tax assets, and therefore Dynegy and DHI recorded valuation allowances resulting in additional state tax expense of $12 million and $10 million, respectively, during 2009.

 

Discontinued Operations

 

Loss From Discontinued Operations Before Taxes

 

For the year ended December 31, 2010, our pre-tax income from discontinued operations was $1 million.  For the year ended December 31, 2009, our pre-tax loss from discontinued operations was $343 million ($222 million after-tax), related to the operation of our Arizona, Bluegrass and Heard County facilities.  Our GEN-WE segment included pre-tax impairment charges of $235 million ($143 million after-tax) related to our Arizona power generation facilities and a pre-tax loss of $82 million ($50 million after-tax) on the completion of the LS Power Transactions.  Additionally, the GEN-WE segment included a pre-tax gain on sale of $10 million ($6 million after-tax) related to our Heard County power generation facility.  Our GEN-MW segment included pre-tax impairment charges of $23 million ($14 million after-tax) related to our Bluegrass power generating facility and a pre-tax loss on the completion of the LS Power Transactions of $22 million ($13 million after-tax) .

 

 

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Income Tax Benefit From Discontinued Operations

 

We recorded an income tax benefit from discontinued operations of $121 million during the year ended December 31, 2009.  This amount  reflects an effective rate of  35 percent.

 

Noncontrolling Interest

 

We recorded $15 million of noncontrolling interest losses for the year ended December 31, 2009, related to our investment in PPEA Holding.  On January 1, 2010, we adopted ASU No. 2009-17.  The adoption of ASU No. 2009-17 resulted in a deconsolidation of our investment in PPEA Holding which was accounted for as an equity method investment until the sale of our interest in PPEA Holding on November 10, 2010.  Please read Note 15—Variable Interest Entities—PPEA Holding Company LLC for further discussion.

 

Year Ended 2009 Compared to Year Ended 2008

 

Operating Income (Loss)

 

Operating loss for Dynegy was $834 million for the year ended December 31, 2009, compared to operating income of $744 million for the year ended December 31, 2008.  Operating loss for DHI was $836 million for the year ended December 31, 2009, compared to operating income of $744 million for year ended December 31, 2008.

 

Our operating loss for the year ended December 31, 2009 was driven, in large part, by $538 million of asset impairments, a $433 million impairment of goodwill and a $124 million fourth quarter 2009 loss on the closing of the LS Power Transactions.  Please read Note 16—Goodwill for further discussion of the goodwill impairments, Note 7—Impairment and Restructuring Charges for further discussion of the asset impairments and Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions—LS Power Transactions for further discussion of the loss on the LS Power Transactions.

 

Mark-to-market losses on forward sales of power associated with our generating assets are included in Revenues in the consolidated statements of operations.  Such losses, which totaled $180 million for the year ended December 31, 2009, were a result of the expiration of certain risk management positions during 2009, for which earnings were recognized in prior periods.  These losses compared to $252 million of mark-to-market gains for the year ended December 31, 2008, when forward market power prices decreased during the period.

 

We do not designate our commodity derivative instruments as cash flow hedges for accounting purposes.  Please read Note 8—Risk Management Activities, Derivatives and Financial Instruments for further discussion.  The resulting mark-to-market accounting treatment results in the immediate recognition of gains and losses within revenues in the consolidated statements of operations due to changes in the fair value of the derivative instruments.  As a result, these mark-to-market gains and losses are not reflected in the consolidated statements of operations in the same period as the underlying power sales from generation activity for which the derivative instruments serve as economic hedges.  Except for those positions that settled in the year ended December 31, 2009, the expected cash impact of the settlement of our open positions (which amounted to a $17 million net asset at December 31, 2009) will be recognized over time largely through the end of 2010 and 2011 based on the prices at which such positions are contracted.  Our overall mark-to-market position and the related mark-to-market value will change as we buy or sell volumes within the forward market and as forward commodity prices fluctuate.

 

 

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Power Generation—Midwest Segment.   Operating loss for GEN-MW was $4 million for the year ended December 31, 2009, compared to operating income of $686   million for the year ended December 31, 2008.  Such amounts do not include results from our Bluegrass power generating facility, which has been reclassified as a discontinued operation for all periods presented.

 

Revenues for the year ended December 31, 2009 decreased by $364 million compared to the year ended December 31, 2008, cost of sales decreased by $78 million and operating and maintenance expense increased by $19 million, resulting in a net decrease of $305 million.  The decrease was primarily driven by the following:

 

●

Mark-to-market losses – GEN-MW’s results for the year ended December 31, 2009 included mark-to-market losses of $112 million related to forward sales, compared to $191 million of mark-to-market gains for the year ended December 31, 2008.  Of the $112 million in 2009 mark-to-market losses, $137 million of losses related to positions that settled in 2009 representing mark-to-market gains recognized in previous periods, partly offset by $25 million of gains related to positions that will settle in 2010 and beyond;

 

●

Decreased tolling/capacity revenues – Tolling revenues decreased by $58 million as a result of expiring contracts at our Kendall and Rocky Road facilities.  This decrease is partially offset by a $43 million increase in capacity sales due to improved capacity pricing plus the additional capacity we were able to sell from the previously tolled facilities;

 

●

Increased operating expense – operating expense increased from $203 million for year ended December 31, 2008 to $222 million for the year ended December 31, 2009, primarily as a result of planned outages at our coal-fired power generating facilities; and

 

●

Lower revenues of $13 million from sales of emissions credits.

 

These items were partly offset by the following:

 

●

Energy sales—GEN-MW’s results from energy sales, including both physical and financial transactions, increased from $647 million for the year ended December 31, 2008 to $690 million for the year ended December 31, 2009.  The negative impact of lower market power prices was more than offset by contracting 2009 volumes at higher energy prices, active management of swap positions, management of option positions and other commercial activities such as the sale and assignment of a multi-year power sales contract.  Additionally, GEN-MW benefited from the reduced impact of basis differential between liquid market and power delivery prices and increased contributions from our natural gas combined-cycle facilities; and

 

●

Midwest production volumes increased two percent due to higher run times associated with natural gas combined-cycle units, which benefited from coal-to-gas switching in PJM.  Our coal volumes decreased primarily due to lower demand as a result of mild summer weather and economic impacts, as well as transmission line outages, increased off-peak wind generation and imports.

 

Depreciation expense increased from $205 million for the year ended December 31, 2008 to $215 million for the year ended December 31, 2009, primarily as a result of projects associated with the Midwest Consent Decree being placed into service.  The increase in depreciation was partly offset by the impact of the assets sold to LS Power in 2009.

 

Operating income for the year ended December 31, 2009 included a pre-tax charge of approximately $76 million for the impairment of goodwill, reflected in Goodwill impairment on our consolidated statements of operations.  Please read Note 16—Goodwill for further discussion.

 

 

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In addition, for the year ended December 31, 2009, we recorded $147 million of impairments of our Renaissance, Riverside/Foothills, Rocky Road and Tilton power generating facilities and related assets, reflected in Impairment and other charges on our consolidated statements of operations.  Please read Note 7—Impairment and Restructuring Charges for further discussion.

 

Operating income for the year ended December 31, 2009 included a $96   million pre-tax charge from sale of our Renaissance, Riverside/Foothills, Rocky Road and Tilton power generating facilities to LS Power, reflected in Gain (loss) on sale of assets in our consolidated statements of operations.  Operating income for the year ended December 31, 2008 included a $56 million pre-tax gain from the sale of our Rolling Hills power generation facility, reflected in Gain (loss) on sale of assets in our consolidated statements of operations.

 

Power Generation—West Segment.   Operating loss for GEN-WE was $218 million for the year ended December 31, 2009, compared to operating income of $123 million for the year ended December 31, 2008.  Such amounts do not include results from our Arizona and Heard County power generating facilities, which have been classified as discontinued operations for all periods presented.

 

Revenues for the year ended December 31, 2009 decreased by $322 million compared to the year ended December 31, 2008, cost of sales decreased by $259 million and operating and maintenance expense increased by $22 million, resulting in a net decrease of $85 million.  The decrease was primarily driven by the following:

 

●

Mark-to-market losses – GEN-WE’s results for the year ended December 31, 2009 included mark to-market losses of $58 million, compared to $50 million of mark-to-market gains for the year ended December 31, 2008.  Of the $58 million in 2009 mark-to-market losses, $15 million related to positions that settled in 2009, and the remaining $43 million related to positions that will settle in 2010 and beyond;

 

●

Energy sales—GEN-WE’s results from energy sales, including both physical and financial transactions, decreased from $98 million for the year ended December 31, 2008 to $94 million for the year ended December 31, 2009, primarily as a result of lower market spark spreads;

 

●

Decreased volumes – Generated volumes were 5.6 million MWh for the year ended December 31, 2009, down from 8.6 million MWh for the year ended December 31, 2008.  The volume decrease was driven in large part by decreased market spark spreads and reduced dispatch opportunities; and

 

●

Increased operating expense – operating expense increased from $98 million for the year ended December 31, 2008 to $120 million for the year ended December 31, 2009, primarily as a result of planned outages at our Moss Landing facility as well as severance and employee retirement obligations associated with our South Bay facility.

 

These decreases were partly offset by increased tolling and capacity revenues of $46 million.

 

Depreciation expense decreased from $77 million for year ended December 31, 2008 to $62 million for the year ended December 31, 2009, largely as a result of an increase in the estimated useful life of one of our generation facilities.

 

Operating loss for the year ended December 31, 2009 included a pre-tax charge of approximately $260 million for the impairment of goodwill, reflected in Goodwill impairments in our consolidated statements of operations.  Please read Note 16—Goodwill for further discussion.

 

In May 2008, we sold our beneficial interest in Oyster Creek Limited for approximately $11 million, and recognized a gain on the sale of approximately $11 million, reflected in Gain (loss) on sale of assets in our consolidated statements of operations.  Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions—Oyster Creek for further discussion.

 

 

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Power Generation—Northeast Segment.   Operating loss for GEN-NE was $444 million for the year ended December 31, 2009, compared to operating income of $67 million for the year ended December 31, 2008.

 

Revenues for the year ended December 31, 2009 decreased by $172 million compared to the year ended December 31, 2008, cost of sales decreased by $171 million and operating and maintenance expense increased by $1 million, resulting in a net decrease of $2 million.  The decrease was primarily driven by the following:

 

●

Mark-to-market losses – GEN-NE’s results for the year ended December 31, 2009 included mark-to-market losses of $10 million related to forward sales, compared to gains of $11 million for the year ended December 31, 2008.  Of the $10 million in 2009 mark-to-market losses, $1 million related to positions that settled in 2009 and the remaining $9 million related to positions that will settle in 2010 and beyond;

 

●

A coal inventory write-down of approximately $11 million recorded during the year ended December 31, 2009; and

 

●

Increased emission allowance costs of approximately $17 million to operate our Northeast facilities due to RGGI requirements that began January 1, 2009.

 

These items were partly offset by the following:

 

●

Energy sales—GEN-NE’s results from energy sales, including both physical and financial transactions, increased from $98 million for the year ended December 31, 2008 to $120 million for the year ended December 31, 2009.  The negative impact from lower market prices was more than offset by contracting 2009 volumes at higher energy prices, active management of swap positions and other commercial activities;

 

●

Additional capacity sales of $14 million;

 

●

Increased sales of emission credits of $7 million; and

 

●

Increased volumes – Volumes produced by our natural gas-fired combined cycle fleet increased as a result of reduced congestion and improved dispatch opportunities at our Independence facility, as well as a reduction in transmission outages at our Casco Bay facility.

 

Depreciation expense decreased from $54 million for the year ended December 31, 2008 to $47 million for the year ended December 31, 2009, primarily due to the 2009 sale of our Bridgeport power generating facility and the 2009 impairments of our Roseton and Danskammer power generation facilities.

 

Operating loss for the year ended December 31, 2009 included a pre-tax charge of approximately $97 million for the impairment of goodwill, reflected in Goodwill impairments in our consolidated statements of operations.  Please read Note 16—Goodwill for further discussion.

 

In addition, we recorded a $179 million impairment of our Bridgeport power generating facility and related assets, reflected in Impairment and other charges in our consolidated statements of operations.  We also recorded a $212 million impairment of our Roseton and Danskammer power generation facilities and related assets, which is also reflected in Impairment and other charges in our consolidated statements of operations.  Please read Note 7—Impairment and Restructuring Charges for further discussion.

 

Operating loss for the year ended December 31, 2009 included a $28   million pre-tax charge from the sale of our Bridgeport power generating facility to LS Power, reflected in Gain (loss) on sale of assets in our consolidated statements of operations.

 

Other.   Dynegy’s other operating loss for the year ended December 31, 2009 was $168 million, compared to an operating loss of $132 million for the year ended December 31, 2008.  DHI’s other operating loss for the year ended December 31, 2009 was $170 million, compared to an operating loss of $132 million for year ended December 31, 2008.  Operating losses in both periods were comprised primarily of general and administrative expenses.

 

 

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Cost of sales for the year ended December 31, 2008 included a benefit from the release of a $9 million liability associated with an assignment of a natural gas transportation contract.  Operating and maintenance expense for the year ended December 31, 2008 included a benefit from the release of $16 million of sales and use tax liability.

 

Gain on sale of assets for the year ended December 31, 2008 included an approximate $15 million gain related to our sale of our remaining NYMEX shares and both membership seats.

 

Consolidated general and administrative expenses increased from $157 million from the year ended December 31, 2008 to $159 million for the year ended December 31, 2009.

 

Losses from Unconsolidated Investments

 

Dynegy’s and DHI’s losses from unconsolidated investments were $71 million and $72 million, respectively, for the year ended December 31, 2009.  The loss includes a loss of $84 million on the sale of our investment in the Sandy Creek Project to LS Power partially offset by equity earnings of $12 million.  Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions—LS Power Transactions for further discussion.   In addition, Dynegy recorded $1 million of earnings related to its former investment in DLS Power Development, included in Other.

 

Dynegy’s and DHI’s losses from unconsolidated investments were $123 million and $40 million, respectively, for the year ended December 31, 2008.  $83 million of Dynegy’s losses related to its investment in DLS Power Development.  These losses included a $24 million impairment charge, a $47 million loss on dissolution as a result of our decision to dissolve this venture and $12 million of equity losses.  Additionally, Dynegy and DHI recognized $40 million of losses related to its investment in the Sandy Creek Project.  These losses were comprised of $53 million primarily associated with our share of the partnership’s losses, partially offset by $13 million for our share of the gain on SCEA’s sale of an 11 percent undivided interest in the Sandy Creek Project.  The $53 million consisted of $40 million mark-to-market losses primarily related to interest rate swap contracts and $13 million of financing costs.  Please read Note 15—Variable Interest Entities—Sandy Creek Project for further discussion.

 

Other Items, Net

 

Dynegy’s and DHI’s other items, net, totaled $11 million and $10 million of income, respectively, for the year ended December 31, 2009, compared to $84 million and $83 million, respectively, of income for the year ended December 31, 2008.  The decrease is primarily associated with approximately $42 million of lower interest income due to lower LIBOR rates in 2009.  In addition, we recorded a $24 million gain related to the liquidation of our investment in a foreign entity during 2008, as the amount accumulated in the translation adjustment component of equity related to that entity was recognized in income upon liquidation of the entity.  Furthermore, during the first quarter 2008, we recognized income of $6 million related to insurance proceeds received in excess of the book value of damaged assets.

 

Interest Expense

 

Dynegy’s and DHI’s interest expense and debt extinguishment costs totaled $461 million for the year ended December 31, 2009, compared to $427 million for the year ended December 31, 2008.  The increase was primarily attributable to $46 million related to debt extinguishment costs for the 2011 Notes and 2012 Notes and $16 million of expense related to the change in value and dedesignation of interest rate swaps associated with PPEA’s Credit Agreement Facility in 2009.  These items were partly offset by a decrease in LIBOR rates on our variable-rate debt in 2009.

 

 

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Income Tax Benefit (Expense)

 

Dynegy reported an income tax benefit from continuing operations of $315 million for the year ended December 31, 2009, compared to an income tax expense from continuing operations of $90 million for the year ended December 31, 2008.  The 2009 effective tax rate was 23 percent, compared to 32 percent in 2008.

 

DHI reported an income tax benefit from continuing operations of $313 million for the year ended December 31, 2009, compared to an income tax expense of $138 million from continuing operations for the year ended December 31, 2008.  The 2009 effective tax rate was 23 percent, compared to 38 percent in 2008.

 

The difference between the statutory rate of 35 percent and the effective rate of 23 percent for Dynegy and DHI for the year ended December 31, 2009 resulted primarily from the effect of the non-deductible goodwill impairment charge, non-deductible losses from the LS Power Transactions and state income taxes in the taxing jurisdictions in which our assets operate.  The income tax benefit for the year ended December 31, 2009 included an overall state tax benefit resulting from current year losses, changes in our state sales profile, the exit from various states due to the LS Power Transactions, and charges of $21 million and $16 million recorded by Dynegy and DHI, respectively, resulting from a change in California state tax law.  We also revised our assumptions around the ability to utilize certain state deferred tax assets, and therefore Dynegy and DHI recorded valuation allowances resulting in additional state tax expense of $12 million and $10 million, respectively, during 2009.

 

For the period ended December 31, 2008, the difference between the effective rates of 32 and 38   percent for Dynegy and DHI, respectively, and the statutory rate of 35 percent resulted primarily from the effect of state income taxes in the taxing jurisdictions in which our assets operate.  In addition, the income tax expense from continuing operations for the year ended December 31, 2008 included a benefit of $10 million related to a permanent difference arising from a gain associated with the liquidation of a foreign entity as well as a benefit of $18 million and $12 million for Dynegy and DHI, respectively, related to adjustments to state tax expense arising from the measurement of temporary differences.

 

Discontinued Operations

 

Loss From Discontinued Operations Before Taxes

 

For the year ended December 31, 2009, our pre-tax loss from discontinued operations was $343 million ($222 million after-tax), related to the operation of our Arizona, Bluegrass and Heard County facilities.  Our GEN-WE segment included pre-tax impairment charges of $235 million ($143 million after-tax) related to our Arizona power generation facilities and a pre-tax loss of $82 million ($50 million after-tax) on the completion of the LS Power Transactions.  Additionally, the GEN-WE segment included a pre-tax gain on sale of $10 million ($6 million after-tax) related to our Heard County power generation facility.  Our GEN-MW segment included pre-tax impairment charges of $23 million ($14 million after-tax) related to our Bluegrass power generating facility and a pre-tax loss on the completion of the LS Power Transactions of $22 million ($13 million after-tax) .

 

For the year ended December 31, 2008, our pre-tax loss from discontinued operations was $31 million ($17 million after-tax).  Dynegy’s GEN-WE segment included a pre-tax impairment charge of $47 million ($27 million after-tax) of our Heard County power generating facility partly offset by $14 million ($8 million after-tax) of income from the operation of our Arizona power generation facilities.  Dynegy’s GEN-MW segment included losses of $2 million ($1 million after-tax) from the operation of the Bluegrass power generating facility.  In addition, Dynegy recorded income of $4 million ($3 million after-tax) related to the receipt of business interruption insurance proceeds in its former NGL segment.

 

 

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Income Tax Benefit From Discontinued Operations

 

We recorded an income tax benefit from discontinued operations of $121 million during the year ended December 31, 2009, compared to an income tax benefit of $14 million during the year ended December 31, 2008.  These amounts reflect effective rates of 35 percent and 45 percent, respectively.

 

Noncontrolling Interest

 

We recorded $15 million of noncontrolling interest losses for the year ended December 31, 2009, compared with $3 million of noncontrolling interest losses for the year ended December 31, 2008 related to our investment in PPEA Holding.  The change in noncontrolling interest losses is primarily related to mark-to-market losses and current period settlements recognized in 2009 related to the interest rate swap agreements associated with the PPEA Credit Agreement Facility.  Effective July 28, 2009, the interest rate swap agreements were no longer accounted for as a cash flow hedges; therefore, the change in mark-to-market value is reflected in our consolidated statement of operations and is no longer reflected in accumulated other comprehensive loss.

 

Outlook

 

Our cash on hand and short-term investments as of December 31, 2010 and our internal forecasted cash flows from operations for 2011 are not expected to be sufficient to fund our planned $265 million capital expenditure program and our $148 million debt service requirements.  Furthermore, using the latest available forward commodity price curves and considering our current derivative contracts, we project that it is likely that we will not be able to comply with our EBITDA to Consolidated Interest Expense covenant contained in our Credit Facility, particularly in the third and fourth quarters of 2011.  Accordingly, as described at “Going Concern” above, we are attempting to amend or replace our existing Credit Facility.

 

We may also seek additional sources of liquidity in an effort to secure sufficient cash to meet our operating needs.  These additional sources of liquidity could include asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination of these.  Please read Capital Structuring Transactions and Asset Dispositions above for more detail.  H owever, we cannot provide any assurances that we will be successful in accomplishing any of these plans.  For additional discussion of factors that may affect our ability to continue as a going concern and the potential consequences of our failure to do so, please see Item 1A —Risk Factors.

 

Our power generation portfolio currently consists of approximately 11,800 MW of generating capacity that is diversified by fuel source (i.e., coal, natural gas and fuel oil) and dispatch type (i.e., baseload, intermediate and peaking facilities).

 

We expect that our future financial results will continue to be sensitive to fuel and commodity prices, especially gas prices and the impact on such prices of shale gas proliferation.  Other factors to which our future financial results will remain sensitive include market structure and prices for electric energy, capacity and ancillary services, including pricing at our plant locations relative to pricing at their respective trading hubs, the volatility of fuel and electricity prices, transportation and transmission logistics, weather conditions and IMA.  Further, there is a trend toward greater environmental regulation of all aspects of our business.  As this trend continues, it is likely that we will experience additional costs and limitations.

 

We have volumetrically hedged nearly 100 percent of our expected generation volumes for 2011 and approximately 25 percent for 2012.  Based on specific market conditions, at any point in time we may enter into transactions that will increase or decrease the portion of our expected output that has been contracted.  Even though we have largely contracted our expected output through 2011, our future operating cash flows during this period may vary based on a number of other factors, including the value of capacity and ancillary services, the operational performance of our generating facilities, the price differential between the locations where we deliver generated power and the liquid market hub, legal, environmental, and regulatory requirements, collateral requirements and other factors.  Further, we may reduce the amount of our expected generation we have volumetrically hedged in order to reduce the collateral postings required to support our current level of hedging activity.

 

 

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GEN-MW.   Our Midwest Consent Decree requires substantial emission reductions from our Illinois coal-fired power plants and the completion of several supplemental environmental projects in the Midwest.  We have achieved all emission reductions scheduled to date under the Midwest Consent Decree and are in the process of installing additional emission control equipment to meet future Midwest Consent Decree emission limits.  We expect our costs associated with the remaining Midwest Consent Decree projects, which we have planned to incur through 2013, to be approximately $230 million.  This estimate includes a number of assumptions about uncertainties beyond our control, such as costs associated with labor and materials.  If the costs of these capital expenditures become great enough to render the operation of the affected power generation facility or facilities uneconomical, we could, at our option, cease to operate the power generation facility or facilities and forego these capital expenditures without incurring any further obligations under the Midwest Consent Decree.  Please read Note 1—Organization and Operations—Going Concern for further discussion.

 

On December 28, 2010, Dynegy announced that it expects to mothball the 176-megawatt Vermilion power generation facility in Oakwood, Illinois, near the end of the first quarter 2011.  Factors influencing our decision include the relatively small size of the facility, older technologies and coal delivery challenges that lead to high production costs, as well as weak electricity demand, a low power pricing environment, and uncertainties over future regulatory requirements.

 

Our Midwest coal requirements are approximately 96 percent contracted in 2011 and 99 percent contracted in 2012.  All forecast coal requirements are 96 percent priced through 2011 and 69 percent are priced through 2012.  Committed volumes that are currently unpriced are subject to a price collar structure.  Our Midwest coal transportation requirements are 100 percent contracted and priced through 2013.  We continue to explore various alternative contractual commitments and financial options, as well as facility modifications, to ensure stable and competitive fuel supplies and to mitigate further supply risks for near- and long-term coal supplies.  Our Midwest expected generation volumes are volumetrically 100 percent hedged through 2011 and approximately 23 percent hedged for 2012.

 

Recent moves by certain MISO market participants expressing their intentions to exit the MISO could mitigate earlier membership increases and impact system reserve margins favorably in the future.  The impacts to MISO capacity market-clearing practices and the resulting prices are unclear at this time as the MISO continues to consult with market stakeholders regarding optimal capacity auction mechanics and product offerings.  In addition, competing initiatives of increased market participation by demand response resources offset by potential retirement of marginal MISO coal capacity due to expected environmental mandates could also affect MISO capacity and energy markets in the future.

 

 

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GEN-WE.   Approximately 70 percent of our power plant capacity in the West is contracted through 2011 under tolling agreements with load-serving entities and RMR agreements with the CAISO.  A significant portion of the remaining capacity is sold as a resource adequacy product in the California market, and much of the expected production associated with our plants without tolls or RMR agreements has been financially hedged.

 

The estimated useful lives of our generation facilities consider environmental regulations currently in place.  With respect to units 6 and 7 at our Moss Landing facility, we are continuing to review the potential impact of the California Water Intake Policy.  We are currently depreciating these units through 2024; however, depending on the ultimate impact of the California Water Intake Policy, we may determine that we will be required to install cooling systems that would render operation of the units uneconomical.  If such a determination were to be made, we could decide to reduce operations or cease to operate the units as early as December 31, 2017.  A decision to cease operations at the end of 2017 would result in additional depreciation expense of approximately $22 million per year, assuming such a determination was to occur in the first quarter of 2011.

 

South Bay’s RMR designation was terminated at the end of 2010, and as a result, the South Bay power generation facility has been decommissioned.  We have a contractual obligation to demolish the facility and remediate specific parcels of the property.  Our cost estimates for the demolition of the facility have not been finalized, but are currently expected to be approximately $40 million, exclusive of certain rental payments that will be due the Port of San Diego.  We expect to begin the demolition in 2012.

 

GEN-NE.   A substantial portion of our physical coal supply and delivery requirements for 2011 are fully contracted and priced with the balance financially hedged.  While we continue to source the majority of our coal supply from South America, having access to both marine and rail unloading facilities at the site affords us opportunities to explore alternative domestic and international supply and delivery options for Danskammer.  In the near term, lower natural gas prices are expected to continue to compress dark spreads and alter the dispatch stack favoring natural gas-fired assets over coal-fired assets during off-peak periods in much of the Northeast.

 

During January 2011, we performed an inspection of our Casco Bay steam turbine.  As a result of this inspection, our Casco Bay facility has been out of service since the middle of January 2011, and is not expected to return to service until the end of the first quarter of 2011, based on a lack of replacement parts available from our supplier.  We plan to evaluate similar equipment at our Moss Landing and Kendall facilities later in 2011 to determine whether turbines at these facilities will need similar repairs.  We expect the financial impact of this matter to be approximately $20 million to $25 million , resulting from lost revenues, increased operating expense and capital expenditures.

 

We continue to maximize revenue opportunities from our merchant plant operations in New York through active participation in the NYISO capacity auctions and ancillary services markets.  While capacity prices have trended lower in New York due to surplus capacity and lower demand, we have contracted approximately 60 percent of our 2011 capacity in the NYISO and 25 percent through 2014 at prices that are favorable compared to current market prices.

 

In New England, four forward capacity auctions have been held since the ISO-NE transitioned to a forward capacity auction market in June of 2010.  Capacity clearing prices have ranged from a high of $4.50 kW-month for the 2010-2011 market period to a low of $2.95 kW-month for the 2012-2013 market period.  These capacity clearing prices represent the floor price, and the actual rate paid to Casco Bay (and other facilities) has been reduced due to oversupply conditions and pro-rationing.  Efforts to implement prospective improvements in the forward capacity market design are currently underway in active proceedings at FERC and in discussions by the ISO and its stakeholders.

 

 

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SEASONALITY

Our revenues and operating income are subject to fluctuations during the year, primarily due to the impact seasonal factors have on sales volumes and the prices of power and natural gas.  Power marketing operations and generating facilities have higher volatility and demand, respectively, in the summer cooling months.  This trend may change over time as demand for natural gas increases in the summer months as a result of increased natural gas-fired electricity generation.  Further, to the extent that climate change may affect weather patterns, this could result in more extreme weather patterns which could impact demand for our products.

CRITICAL ACCOUNTING POLICIES

Our Accounting Department is responsible for the development and application of accounting policy and control procedures.  This department conducts these activities independent of any active management of our risk exposures, is independent of our business segments and reports to the Chief Financial Officer.

The process of preparing financial statements in accordance with GAAP requires our management to make estimates and judgments.  It is possible that materially different amounts could be recorded if these estimates and judgments change or if actual results differ from these estimates and judgments.  We have identified the following seven critical accounting policies that require a significant amount of estimation and judgment and are considered important to the portrayal of our financial position and results of operations:

 

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Revenue Recognition and Valuation of Risk Management Assets and Liabilities;

 

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Estimated Useful Lives;

 

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Valuation of Tangible and Intangible Assets;

 

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Accounting for Contingencies, Guarantees and Indemnifications;

 

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Accounting for Variable Interest Entities;

 

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Accounting for Income Taxes; and

 

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Valuation of Pension and Other Post-Retirement Plans Assets and Liabilities.

Revenue Recognition and Valuation of Risk Management Assets and Liabilities

We earn revenue from our facilities in three primary ways: (i) the sale of both fuel and energy through both physical and financial transactions to optimize the financial performance of our generating facilities; (ii) sale of capacity; and (iii) sale of ancillary services, which are the products of a generation facility that support the transmission grid operation, allow generation to follow real-time changes in load, and provide emergency reserves for major changes to the balance of generation and load.  We recognize revenue from these transactions when the product or service is delivered to a customer, unless they meet the definition of a derivative.  Please read “Derivative Instruments—Generation” for further discussion of the accounting for these types of transactions.

Derivative Instruments–Generation.   We enter into commodity contracts that meet the definition of a derivative.  These contracts are often entered into to mitigate or eliminate market and financial risks associated with our generation business.  These contracts include power sales contracts, fuel purchase contracts, options, swaps, and other instruments used to mitigate variability in earnings due to fluctuations in market prices.  There are three different ways to account for these types of contracts: (i) as an accrual contract, if the criteria for the “normal purchase normal sale” exception are met and documented; (ii) as a cash flow or fair value hedge, if the criteria are met and documented; or (iii) as a mark-to-market contract with changes in fair value recognized in current period earnings.  All derivative commodity contracts that do not qualify for the “normal purchase normal sale” exception are recorded at fair value in risk management assets and liabilities on the consolidated balance sheets.  If the derivative commodity contract has been designated as a cash flow hedge, the changes in fair value are recognized in earnings concurrent with the hedged item.  Changes in the fair value of derivative commodity contracts that are not designated as cash flow hedges are recorded currently in earnings.  Because derivative contracts can be accounted for in three different ways, and as the “normal purchase normal sale” exception and cash flow and fair value hedge accounting are elective, the accounting treatment used by another party for a similar transaction could be different from the accounting treatment we use.  To the extent a party elects to apply cash flow hedge accounting for qualifying transactions, there is generally less volatility in the statements of operations as the effective portion of the changes in the fair values of the derivative instruments is recognized through equity.  We do not utilize hedge accounting for our commodity contracts.

 

 

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Entities may choose whether or not to offset related assets and liabilities and report the net amounts on their consolidated balance sheet if the right of setoff exists.  We execute a significant volume of transactions through a futures clearing manager.  Our daily cash payments (receipts) to (from) our futures clearing manager consist of three parts: (i) fair value of open positions (exclusive of options) (“Daily Cash Settlements”); (ii) initial margin requirements related to open positions (exclusive of options) (“Initial Margin”); and (iii) fair value of options (“Options”, and collectively with Initial Margin, “Collateral”).  We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement and we elect not to offset the fair value of amounts recognized for the Daily Cash Settlements paid or received against the fair value of amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement.  As a result, our consolidated balance sheets present derivative assets and liabilities, as well as the related cash collateral paid or received, on a gross basis.

Derivative Instruments–Financing Activities.   We are exposed to changes in interest rate risk through our variable and fixed rate debt.  In order to manage our interest rate risk, we enter into interest rate swap agreements that meet the definition of a derivative.  All derivative instruments are recorded at their fair value on the consolidated balance sheet.  If the derivative is designated as a cash flow hedge, the effective portions of the changes in the fair value of the derivative are recorded in OCI and the realized gains and losses related to these derivatives are recognized in earnings in the same period as the settlement of the underlying hedged transaction.  If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized currently in earnings.  If the derivative is not designated as a hedge, the change in value is recognized currently in earnings.  To the extent a party elects to apply hedge accounting for qualifying transactions, there is generally less volatility in the statements of operations as a portion of the changes in the fair value of the derivative instruments is recognized through equity.

Fair Value Measurements.   Fair value is 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 (exit price).  We utilize a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of our assets and liabilities measured and reported at fair value.  Where appropriate, valuation adjustments are made to account for various factors, including the impact of our credit risk, our counterparties’ credit risk and bid-ask spreads.  We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable, market corroborated, or generally unobservable.  We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information.  Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  We classify fair value balances based on the observability of those inputs.  The inputs used to measure fair value have been placed in a hierarchy based on priority.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  The three levels of the fair value hierarchy are as follows:

 

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Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  Level 1 primarily consists of financial instruments such as listed equities.

 

 

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Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.  Level 2 includes those financial instruments that are valued using models or other valuation methodologies.  These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.  Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.  Instruments in this category include non-exchange-traded derivatives such as over the counter forwards, options and repurchase agreements.

 

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Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources.  These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.  Level 3 instruments include those that may be more structured or otherwise tailored to our needs.  At each balance sheet date, we perform an analysis of all instruments and include in Level 3 all of those whose fair value is based on significant unobservable inputs.

The determination of the fair values incorporates various factors.  These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities.  Valuation adjustments are generally based on capital market implied ratings evidence when assessing the credit standing of our counterparties and when applicable, adjusted based on management’s estimates of assumptions market participants would use in determining fair value.

Assets and liabilities from risk management activities may include exchange-traded derivative contracts and OTC derivative contracts.  Some exchange-traded derivatives are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets.  In such cases, these exchange-traded derivatives are classified within Level 2.  OTC derivative trading instruments include swaps, forwards, options and complex structures that are valued at fair value.  In certain instances, these instruments may utilize models to measure fair value.  Generally, we use a similar model to value similar instruments.  Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs.  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  Certain OTC derivatives trade in less active markets with a lower availability of pricing information.  In addition, complex or structured transactions, such as heat-rate call options, can introduce the need for internally-developed model inputs that might not be observable in or corroborated by the market.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.

Estimated Useful Lives

The estimated useful lives of our long−lived assets are used to compute depreciation expense and future AROs and are used in impairment testing.  Estimated useful lives are based, among other things, on the assumption that we provide an appropriate level of capital expenditures while the assets are still in operation. Estimated lives could be impacted by such factors as future energy prices, environmental regulations, various legal factors and competition. If the useful lives of these assets were found to be shorter than originally estimated, depreciation expense may increase, liabilities for future AROs may be insufficient and impairments in carrying values of tangible and intangible assets may result.

The estimated useful lives of our generation facilities consider environmental regulations currently in place.  With respect to units 6 and 7 at our Moss Landing facility, we are continuing to review the potential impact of the California Water Intake Policy.  We are currently depreciating these units through 2024; however, depending on the ultimate impact of the California Water Intake Policy, we may determine that we would be required to install cooling systems that would render operation of the units uneconomical.  If such a determination were to be made, we could decide to reduce operations or cease to operate the units as early as December 31, 2017.  A decision to cease operations at the end of 2017 would result in additional depreciation expense of approximately $22 million per year, assuming such a determination was to occur in the first quarter of 2011.  In addition to the California Water Intake Policy, other environmental regulations could be introduced or enacted at any time, requiring us to adjust the estimated useful lives of our other generation facilities, and potentially resulting in a significant acceleration of depreciation expense.

 

 

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Valuation of Tangible and Intangible Assets

We evaluate long-lived assets, such as property, plant and equipment and investments for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.  Factors we consider important, which could trigger an impairment analysis, include, among others:

 

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significant underperformance relative to historical or projected future operating results;

 

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significant changes in the manner of our use of the assets or the strategy for our overall business, including an expectation that the asset will be sold;

 

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significant negative industry or economic trends; and

 

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significant declines in stock value for a sustained period.

We assess the carrying value of our property, plant and equipment and intangible assets subject to amortization.  If an impairment is indicated, the amount of the impairment loss recognized is determined by the amount the carrying value exceeds the estimated fair value of the assets.  For assets identified as held for sale, the carrying value is compared to the estimated sales price less costs to sell.  Please read Note 7—Impairment and Restructuring Charges for discussion of impairment charges we recognized in 2010, 2009 and 2008.

We review our equity investments by comparing the book value of the investment to the estimated fair value to determine if an impairment is required.  We record a loss when the decline in value is considered other than temporary.  Please read Note 15—Variable Interest Entities—for further discussion of our accounting for the impairment of our former equity investments in PPEA Holding Company and DLS Power Holdings.

Accounting standards 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.  In estimating fair value, we use discounted cash-flow projections, recent comparable market transactions, if available, or quoted prices.  We consider assumptions that third parties would make in estimating fair value, including the highest and best use of the asset.  There is a significant amount of judgment involved in cash-flow estimates, including assumptions regarding market convergence, discount rates and capacity prices.  The assumptions used by another party could differ significantly from our assumptions.

We previously assessed the carrying value of our goodwill annually on November 1 or when circumstances warrant.  Step 1 of the goodwill impairment test compares the fair value of a reporting unit to its carrying amount.  Step 2 of the goodwill impairment test compares the implied fair value of each reporting unit’s goodwill with the carrying amount of such goodwill through a hypothetical purchase price allocation of the fair value of the reporting unit to the reporting unit’s tangible and intangible assets.  As of March 31, 2009, our goodwill was fully impaired.  Please read Note 16—Goodwill for further discussion of our impairment analysis.

Accounting for Contingencies, Guarantees and Indemnifications

We are involved in numerous lawsuits, claims, proceedings, and tax-related audits in the normal course of our operations.  We record a loss contingency reserve for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated.  We review our loss contingency reserves on an ongoing basis to ensure that we have appropriate reserves recorded on our consolidated balance sheets.  These reserves are based on estimates and judgments made by management with respect to the likely outcome of these matters, including any applicable insurance coverage for litigation matters, and are adjusted as circumstances warrant.  Our estimates and judgments could change based on new information, changes in laws or regulations, changes in management’s plans or intentions, the outcome of legal proceedings, settlements or other factors.  If different estimates and judgments were applied with respect to these matters, it is likely that reserves would be recorded for different amounts.  Actual results could vary materially from these reserves.

 

 

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Liabilities are recorded when an environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements.  Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability.  These assumptions involve the judgments and estimates of management and any changes in assumptions could lead to increases or decreases in our ultimate liability, with any such changes recognized immediately in earnings.

We disclose and account for various guarantees and indemnifications entered into during the course of business.  When a guarantee or indemnification is entered into, an estimated fair value of the underlying guarantee or indemnification is recorded.  Some guarantees and indemnifications could have significant financial impact under certain circumstances and management also considers the probability of such circumstances occurring when estimating the fair value.  Actual results may materially differ from the estimated fair value of such guarantees and indemnifications.

Please read Note 22—Commitments and Contingencies for further discussion of our commitments and contingencies.

Accounting for Variable Interest Entities

We evaluate certain entities to determine which party is considered the primary beneficiary of the entity and thus required to consolidate it in its financial statements.  We were an investor, with independent third parties, in PPEA Holding.  PPEA Holding is a variable interest entity, and there is a significant amount of judgment involved in the analysis used to determine the primary beneficiary.  Effective January 1, 2010, we adopted ASU No. 2009-17, which revised the criteria for determining the primary beneficiary of a variable interest entity.  The analysis required by ASU No. 2009-17 included determining the activities that most significantly impact the performance of the variable interest entity, who has the power to direct those activities and who has the obligation to absorb losses or the right to receive benefits that could potentially be significant to the variable interest entity.  Under this model, we concluded that we were not the primary beneficiary of PPEA Holding because the power to direct the activities that most significantly impact PPEA Holding’s economic performance was shared by the members of PPEA Holding and the participants in the Plum Point Project.  We determined the activities that most significantly impact PPEA Holding’s economic performance were changes to the costs to complete the facility, modifications to the off-take agreements, and/or changes in the financing structure.  As a result, we deconsolidated our investment in PPEA Holding which was accounted for as an equity method investment until we sold our interest in the investment on November 10, 2010.  Please read Note 15—Variable Interest Entities—PPEA Holding Company LLC for further discussion.

Prior to the adoption of ASU No. 2009-17, the analysis included assumptions about forecasted cash flows, construction costs, and plant performance.  Under the previous accounting model, we had concluded that we were the primary beneficiary of PPEA Holding and therefore consolidated the entity in our consolidated financial statements.

If different judgment had been applied, a different conclusion about the  primary beneficiary of this entity could have resulted, which would have significantly impacted our financial condition, results of operations and cash flows.

 

 

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