Edgar Filing: DYNEGY INC.

Form 8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported):

May 15, 2007

DYNEGY INC.

(formerly named Dynegy Acquisition, Inc.)

DYNEGY ILLINOIS INC.

(formerly named Dynegy Inc.)

Delaware

Illinois

001-33443

1-15659

20-5653152

74-2928353

(State or other jurisdiction

of incorporation)

(Commission File Number)

(IRS Employer

Identification No.)


1000 Louisiana, Suite 5800, Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code (713) 507-6400

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01. Other Events.

On January 31, 2007, we entered into an agreement to sell our interest in the Calcasieu power generation facility to Entergy Gulf States, Inc. (“Entergy”). Subject to regulatory approval, the transaction is expected to close in early 2008. We reported our operations with respect to the Calcasieu facility as discontinued operation in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2007.

This Current Report on Form 8-K was prepared to provide revised financial information that presents our operations with respect to the Calcasieu facility as discontinued operations for all periods presented in our Annual Report on Form 10-K for the year ended December 31, 2006, filed on February 27, 2007 (“2006 Form 10-K”). It should be noted that our net income (loss) was not impacted by the reclassification of Calcasieu to discontinued operations.

Please note we have not otherwise updated our financial information or business discussion for activities or events occurring after the date this information was presented in our 2006 Form 10-K. You should read our Quarterly Report on Form 10-Q for the period ended March 31, 2007 and our Current Reports on Form 8-K and any amendments thereto for updated information regarding our business, financial conditions and results of operations.

This filing includes updated information for the following items included in our 2006 Form 10-K:

Item 6. Selected Financial Data

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

Item 8. Financial Statements and Supplementary Data

Unaffected items of our 2006 Form 10-K have not been repeated in this Form 8-K.

In this document, except as otherwise indicated or unless the context requires otherwise, (i) references to “Dynegy”, “we”, “our”, “our company”, “us” or “the company” refer to the combined business of Dynegy Inc. and its subsidiaries, including, but not limited to, the entities acquired in connection with the LS Power combination, as well as Dynegy Illinois Inc. before it became a wholly owned subsidiary of Dynegy as a result of such merger.

The Annual Report on Form 10-K referred to in this document was filed by Dynegy Illinois Inc., formerly named Dynegy Inc., which is our predecessor registrant.

Cross-references that are included in the above items and that refer to information included on page numbers that are preceded by an “F” refer to the corresponding page included in this filing. Other cross-references are to pages in our 2006 Form 10-K.

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

Dynegy’s Selected Financial Data


	Year Ended December 31,
	2006			2005			2004			2003			2002
	(in millions, except per share data)
Statement of Operations Data (1):
Revenues	$	2,016		$	2,311		$	2,444		$	2,586		$	2,093
Depreciation and amortization expense		(228	)		(218	)		(232	)		(369	)		(374	)
Goodwill impairment		—			—			—			(311	)		(814	)
Impairment and other charges		(119	)		(46	)		(78	)		(225	)		(176	)
General and administrative expenses		(196	)		(468	)		(330	)		(315	)		(297	)
Operating income (loss)		91			(835	)		(100	)		(774	)		(1,148	)
Interest expense and debt conversion expense		(631	)		(389	)		(453	)		(503	)		(241	)
Income tax benefit		157			394			172			294			336
Net loss from continuing operations		(330	)		(802	)		(180	)		(816	)		(1,218	)
Income (loss) from discontinued operations (3)		(4	)		897			165			84			(1,135	)
Cumulative effect of change in accounting principles		1			(5	)		—			40			(234	)
Net income (loss)	$	(333	)	$	90		$	(15	)	$	(692	)	$	(2,587	)
Net income (loss) applicable to common stockholders (4)		(342	)		68			(37	)		321			(2,917	)
Basic earnings (loss) per share from continuing operations	$	(0.74	)	$	(2.13	)	$	(0.53	)	$	0.53		$	(4.23	)
Basic net income (loss) per share		(0.75	)		0.18			(0.10	)		0.86			(7.97	)
Diluted earnings (loss) per share from continuing operations	$	(0.74	)	$	(2.13	)	$	(0.53	)	$	0.50		$	(4.23	)
Diluted net income (loss) per share		(0.75	)		0.18			(0.10	)		0.78			(7.97	)
Shares outstanding for basic EPS calculation		459			387			378			374			366
Shares outstanding for diluted EPS calculation		509			513			504			423			370
Cash dividends per common share	$	—		$	—		$	—		$	—		$	0.15
Cash Flow Data:
Net cash provided by (used in) operating activities	$	(194	)	$	(30	)	$	5		$	876		$	(25	)
Net cash provided by (used in) investing activities		358			1,824			262			(266	)		677
Net cash used in financing activities		(1,342	)		(873	)		(115	)		(900	)		(44	)
Cash dividends or distributions to partners, net		(17	)		(22	)		(22	)		—			(55	)
Capital expenditures, acquisitions and investments		(163	)		(315	)		(314	)		(338	)		(981	)


	December 31,
	2006		2005		2004		2003		2002
	(in millions)
Balance Sheet Data (2):
Current assets	$	2,082	$	3,706	$	2,728	$	3,074	$	7,574
Current liabilities		1,259		2,116		1,802		2,450		6,748
Property and equipment, net		4,951		5,323		6,130		8,178		8,458
Total assets		7,630		10,126		9,843		12,801		20,020
Long-term debt (excluding current portion)		3,190		4,228		4,332		5,893		5,454
Notes payable and current portion of long-term debt		68		71		34		331		861
Serial preferred securities of a subsidiary		—		—		—		11		11
Subordinated debentures		—		—		—		—		200
Series B Preferred Stock (5)		—		—		—		—		1,212
Series C convertible preferred stock		—		400		400		400		—
Minority interest		—		—		106		121		146
Capital leases not already included in long-term debt		6		—		—		—		15
Total equity		2,267		2,140		1,956		1,975		2,256

(1)

The Sithe Energies (February 1, 2005) and Northern Natural (February 1, 2002) acquisitions were accounted for in accordance with the purchase method of accounting and the results of operations attributable to the acquired businesses are included in our financial statements and operating statistics beginning on the acquisitions’ effective date for accounting purposes.

(2)

The Sithe Energies and Northern Natural acquisitions were each 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 dates of each transaction. See note (1) above.

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

•

Northern Natural (sold third quarter 2002);

•

U.K. Storage—Hornsea facility (sold fourth quarter 2002) and Rough facility (sold fourth quarter 2002);

•

DGC (portions sold in fourth quarter 2002 and first and second quarters 2003);

•

Global Liquids (sold fourth quarter 2002);

•

U.K. CRM (substantially liquidated in first quarter 2003);

•

DMSLP (sold fourth quarter 2005); and

•

Calcasieu generation facility (entered into an agreement to sell in first quarter 2007).

(4)	In August 2003, we consummated a restructuring of our Series B Preferred Stock in which we recognized an approximate $1 billion gain on the restructuring.

(5)	The 2002 amount equals $1.5 billion in proceeds related to outstanding Series B Preferred Stock less a $660 million implied dividend recognized in connection with a beneficial conversion option plus $372 million in accretion of the implied dividend through December 31, 2002.

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 a holding company 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: (1) the Midwest segment (GEN-MW); (2) the Northeast segment (GEN-NE); and (3) the South segment (GEN-SO). We also separately report the results of our CRM business, which primarily consists of the Kendall power tolling arrangement (excluding the Sithe toll which is now in our GEN-NE segment and is an intercompany agreement) as well as our legacy natural gas, power and emission trading positions. Because of the diversity among their respective operations, 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 and interest. As described below, our NGL business, which was conducted through DMSLP and its subsidiaries, was sold to Targa on October 31, 2005. Additionally, as described below, our former REG business, which was conducted through Illinois Power and its subsidiaries, was sold to Ameren Corporation on September 30, 2004.

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 CRM business, our corporate-level expenses and our discontinued businesses. This “Overview” section concludes with a discussion of our 2006 company highlights, our key objectives and our ongoing strategic outlook. Please note that this “Overview” section is merely a summary and should be read together with the remainder of this Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, as well as our audited consolidated financial statements, including the notes thereto, and the other information included in this report.

Business Discussion

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 are the prices for power, natural gas and coal, which in turn are largely driven by supply and demand. As further discussed below, demand for power can vary regionally due to weather and general economic conditions, among other things. Power supplies similarly vary by region and are impacted significantly by available generating capacity, transmission capacity and federal and state regulation. We are also impacted by the relationship between prices for power and natural gas and prices for power and fuel oil, commonly referred to as the “spark spread”, which impacts the margin we earn on the electricity we generate. We believe that our significant coal-fired generating facilities partially mitigate our sensitivity to changes in the spark spread, in that our delivered cost of coal, particularly in the Midwest region, is relatively stable and positions us for potential increases in earnings and cash flows in an environment where both power and natural gas prices increase.

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

•

our ability to control capital expenditures, which primarily are limited to maintenance, safety, environmental and reliability projects, and to control other costs through disciplined management;

•

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

•

the cost of compliance with existing and future environmental requirements that are likely to be more stringent and more comprehensive; and

•

the evaluation of our generation portfolio for rationalization of non-strategic assets.

Please read Item 1A. Risk Factors beginning on page 18 of our 2006 Form 10-K 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.

Power Generation—Midwest Segment. Our assets in the Midwest include a coal-fired fleet and a natural gas-fired fleet. Although the primary factor affecting earnings and cash flows in GEN-MW, especially for the coal-fired fleet, is the market price of power, the following specific factors also affect or could affect the performance of this reportable segment:

•

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

•

Any pursuit of the state of Illinois of legislation for a limitation of CO₂ emissions that is more stringent than federal guidelines could impose additional costs on our facilities;

•

Political, legislative, judicial and/or regulatory actions over the next several months that could alter the Illinois auction results substantially

•

A significant amount of cash will be utilized for capital expenditures required to comply with the Midwest consent decree for the next few years; and

•

Earnings and cash flows are primarily weather driven for our natural gas-fired fleet. A warm summer or cold winter increases demand for electricity, which in turn can increase run time of our peaking units and the demand for capacity and energy from these units.

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

•

Our ability to maintain sufficient coal and fuel oil inventories, including the continued deliveries of coal in a consistent and timely manner, impacts our ability to serve the critical winter and summer on-peak load;

•

State-driven programs aimed at capping mercury and carbon dioxide emissions that are more stringent than federal guidelines could impose additional costs on our facilities; and

•

The outcome of administrative proceedings and litigation specific to water intake issues could materially impact operating costs at two of our New York facilities.

Power Generation—South Segment. Assets in our South segment are all natural gas-fired facilities. Our ERCOT facility is a baseload facility, and our other wholly-owned assets in the segment are peaking units. The following specific factors also impact or could impact the performance of this reportable segment:

•

For the peaking units, earnings and cash flows are primarily weather driven. A warm summer or cold winter increases the demand for electricity, which in turn can increase the run time of our peaking plants;

•

Our ability to enter into capacity agreements for our peaking units could impact future results;

•

Wholesale market design changes in ERCOT could impact our ability to sell the remainder of the energy and ancillary products of the CoGen Lyondell facility into the bilateral ERCOT markets or the daily ERCOT market, and

•

Our agreement dated January 31, 2007, to sell our interest in the Calcasieu power generation facility to Entergy. Subject to regulatory approval the transaction is expected to close in early 2008.

Customer Risk Management

Our CRM segment is comprised largely of the Kendall power tolling arrangement (excluding the Sithe toll which is now in our GEN-NE segment and is an intercompany agreement). We have agreed to acquire the Kendall facility from the LS Entities, and upon the closing of that acquisition the Kendall tolling arrangement will become an intercompany obligation under our GEN-MW segment. As a result, the accounting impact of the toll would be eliminated in our consolidated results. In addition, our CRM segment includes remaining natural gas, power and emission trading positions. We are actively pursuing opportunities to terminate, assign or renegotiate the terms of our remaining obligations under these agreements when circumstances are economically advantageous to us.

Regarding our legacy natural gas, power and emission trading positions, we have substantially reduced the size of our mark-to-market portfolio since October 2002, when we initiated our efforts to exit the CRM business. Our remaining natural gas transactions still require us to purchase natural gas for our customers; however, those cash requirements are partially

offset by the proceeds received from financial contracts hedging a significant portion of the supply. Therefore, the profit and loss impacts of price movements are mitigated by these offsetting financial positions. All that remains of our power trading business, exclusive of our power tolling arrangement, is a minimal number of positions that will remain until 2010. Finally, we have a forward obligation to deliver SO₂ emissions allowances through 2008. Our financial statements reflect the gain or loss on this obligation resulting from the price fluctuation in SO₂ emissions allowances. This obligation will be satisfied by our current inventory of physical SO₂ emissions allowances, and such inventory is valued at the lower of cost or market, in accordance with GAAP. Upon settlement of the forward obligation, we will recognize a gain to the extent that the delivery price is higher than the book value of our inventory. Upon delivery of the emissions allowances, we expect a positive cash flow as the third party makes payment for the emissions allowances. The inventory of emissions allowances that we use to fulfill our forward obligation is separate from the inventory and needs of our power generation business.

Other

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

•

interest expense, which reflects debt with a weighted-average rate of approximately 8%, and will continue to reflect our non-investment grade credit ratings;

•

general and administrative costs (G&A), with respect to which we have implemented a number of initiatives that have yielded savings, and which will be impacted by, among other things, (i) any future corporate-level litigation reserves or settlements; (ii) potential funding requirements under our pension plans; and (iii) increased G&A associated with additional resources required for the management and administration of assets acquired through the planned merger with the LS Entities; and

•

income taxes, which will be impacted by our ability to realize our significant deferred tax assets, including loss carryforwards.

Discontinued Businesses

Natural Gas Liquids. Our natural gas liquids business, which we sold to Targa in October 2005, was comprised of our natural gas gathering and processing assets and integrated downstream assets used to fractionate, store, terminal, transport, distribute and market natural gas liquids. NGL’s results are reflected in Discontinued Operations in our consolidated statements of operations.

Regulated Energy Delivery. Our regulated energy delivery business was comprised of our Illinois Power subsidiary prior to its sale to Ameren in September 2004. REG’s results are reflected in Continuing operations in our consolidated statements of operations due to our significant continuing involvement with Ameren through power sales agreements.

Important Events

Pending LS Power Combination. On September 14, 2006, we entered into the Merger Agreement with the LS Entities, part of the LS Power Group, a privately held power plant investor, developer and manager, to combine a portion of the LS Entities’ operating generation portfolio with our generation assets, and for us to acquire a 50 percent ownership interest in a development company that is currently controlled by the LS Entities. The combined company (“New Dynegy”) will have nearly 20,000 MW of generating capacity. Upon completion of the Merger Agreement, which is subject to the affirmative vote of the holders of at least two-thirds of our Class A common stock and the satisfaction of other conditions, the combined company will own 29 operating power plants in 13 states (excludes the 351 MW Calcasieu generating facility, which we have agreed to sell to Entergy) employing a balanced mix of fuel sources with baseload, intermediate, and peaking dispatch capabilities, enhanced cash flow-generating opportunities, and significant scale and scope in three key geographic regions. The expanded portfolio will also include a controlling interest in the Plum Point facility, a 665 MW coal-fired plant currently under construction in Arkansas. Additionally, the development joint venture (referred to herein as the development company) will provide us with a 50 percent ownership interest in an established growth vehicle. The LS Entities’ current development activities include nine projects totaling more than 7,600 MW in various stages of development and approximately 2,300 MW of repowering and/or expansion opportunities.

Under the terms of the Merger Agreement, at closing the LS Entities will receive 340 million shares of New Dynegy’s Class B common stock, $100 million in cash and $275 million aggregate principal amount of notes to be issued by New Dynegy. New Dynegy will also assume approximately $1.9 billion in net debt (debt less restricted cash and investments) from the LS Entities. Please read Note 3—Business Combinations and Acquisitions—LS Power on page F-17 for further discussion of the terms of the Merger Agreement as well as the proxy statement/prospectus of Dynegy Acquisition, Inc. filed with the SEC on February 13, 2007.

Illinois Resource Procurement Auction. As a result of the Illinois resource procurement auction, in September 2006, DPM entered into two SFCs with subsidiaries of Ameren Corporation (the “Ameren Illinois Utilities”) to provide the Ameren Illinois Utilities with capacity, energy and related services.

Both of the SFCs are for services required by the Ameren Illinois Utilities to serve their residential and commercial electric customers starting January 1, 2007. The products to be provided by DPM under both SFCs include electric energy and certain ancillary and other services necessary to serve a full-requirements load. The first SFC extends through May 31, 2008 and is for 24 tranches of up to 50 MW per tranche. This amount translates to approximately 22.43% of the total Ameren Illinois Utilities’ relevant customers’ load during each hour of the contract period. The pricing for the first SFC is $64.77 per MW. The second SFC extends through May 31, 2009 and is for four tranches of up to 50 MW per tranche. This amount translates to approximately 3.74% of the total Ameren Illinois Utilities’ relevant customers’ load during each hour of the contract period. The pricing for the second SFC is $64.75 per MW. There is a possibility of political, legislative, judicial and/or regulatory actions over the next several months that could substantially affect the ability of the Ameren Illinois Utilities to honor their contractual commitments under the SFCs. We cannot predict the outcome of the ongoing actions, but an adverse result could negatively impact our financial position, results of operations and cash flows.

Liability Management. We initiated several transactions to reduce debt and other obligations as well as enhance our capital structure during 2006 and accomplished the following:

•

March 2006—we entered into a third amended and restated credit agreement.

•

April 2006—we completed a tender offer and consent solicitation in which we purchased $151 million of our $225 million outstanding Second Priority Senior Secured Floating Rate Notes due 2008 (the “2008 Notes”), substantially all of our $625 million 9.875% Second Priority Senior Secured Notes due 2010 and all $900 million of our 10.125% Second Priority Senior Secured Notes due 2013.

•

April 2006—we issued $750 million aggregate principal amount of our 8.375% Senior Unsecured Notes due 2016 in a private offering.

•

April 2006—we entered into a fourth amended and restated credit agreement.

•

May 2006—we completed an offer to convert all $225 million of our outstanding 4.75% Convertible Subordinated Debentures due 2023 into shares of our Class A common stock and cash.

•

May 2006—we completed a public offering of 40.25 million shares of our Class A common stock, including 5.25 million shares purchased pursuant to an underwriters’ over-allotment option, for proceeds of $23 million.

•

May 2006—we redeemed from Chevron all 8 million shares of our outstanding Series C convertible preferred stock for a cash purchase price of $400 million.

•

May 2006—we entered into a $150 million Term Loan structured as a new tranche under the Fourth Amended and Restated Credit Facility.

•

July 2006—we redeemed all $74 million of our remaining 2008 Notes.

•

July 2006—we issued $297 million additional principal amount of our 8.375% Senior Unsecured Notes due 2016 in exchange for all $419 million of outstanding Independence subordinated debt.

•

November 2006—we repaid the $150 million Term Loan with proceeds from the sale of the Rockingham facility.

Please read Note 12—Debt beginning on page F-36 for further discussion.

Other. In addition to these events, we also accomplished the following:

•

March 2006—we completed the termination of the Sterlington long-term wholesale power-tolling contract with Ouachita Power LLC with a cash payment of approximately $370 million.

•

March 2006—we completed our acquisition of NRG’s 50% ownership interest in the entity that owns the Rocky Road power plant, a 330-megawatt natural gas-fired peaking facility near Chicago (of which Dynegy already owned 50%). In addition, we completed the sale to NRG of our 50% ownership interest in a joint venture between us and NRG that has ownership in power plants in southern California. As a result of these two transactions, we received net cash proceeds of approximately $165 million from NRG.

•

November 2006—we completed the sale of our Rockingham peaking facility to Duke Power for $194 million.

Key Objectives

First and foremost, we are focused on closing the Merger Agreement and related transactions with the LS Entities and integrating the two portfolios. If the transaction is consummated, we intend to use the combined company’s power generation facility base and development portfolio as a platform for future growth and to take advantage of market opportunities, including commodity price volatility and expected regional market recoveries, to enhance our financial performance. We believe the combined company will be positioned to participate in further industry consolidation opportunities and to capitalize on expected regional power market recoveries designed to improve the predictability and quality of our cash flows.

Our commercial objectives are focused on three elements:

•

Employing a business model and capital structure appropriate for a commodity cyclical business;

•

Maintaining a diverse portfolio of assets consisting of both low-cost plants and those that can provide reliability and other services to the markets both during peak-demand periods and as overall regional electric demand increases over time; and

•

Ensuring that all of our power generation facilities are ready to produce electricity when market demand and, therefore, market price, is highest.

More specifically, our business strategy includes the following:

Employ a Commodity Cyclical Business Model. We intend to optimize our assets by selling electricity and capacity into the spot and term markets when pricing is most attractive. This objective is best achieved through a diverse portfolio of assets commercialized through a combination of spot market sales and term contracts. While we do not have a prescribed allocation of volumes between spot and term market sales, we generally intend to rely on our low-cost coal facilities and term contractual sales arrangements to provide a base level of cash flow, while preserving financial exposure to market prices. We believe this strategy will allow us to benefit from both short-term and long-term market price increases. Consequently, our financial results will be sensitive to, and generally correlated with, commodity prices (especially natural gas prices, regional power prices and the “spread” between them).

We intend to maintain certain longer-term sales arrangements while retaining an ability to participate in near-term markets through both physical transactions and financial hedges, thereby creating a more stable portfolio that, while dependent on cyclical commodity markets, is also positioned to capture higher energy margins and improved capacity pricing.

Establish an Appropriate Capital Structure. We believe that the power industry is a commodity cyclical business with significant commodity price volatility and a considerable capital investment requirement. Thus, maximizing economic returns in this market environment requires a capital structure that can withstand power price volatility as well as a commercial strategy that captures the value associated with both short-term and long-term price trends. We intend to maintain a capital structure that is suitable for our commercial strategy and the commodity cyclical market in which we operate. Maintaining appropriate debt levels, maturities, and overall liquidity are key elements of this capital structure.

Consistent with these objectives, we are exploring a number of options to ensure an appropriate capital structure. Considerations include modifying the existing DHI bank debt arrangements, including increasing DHI’s revolving credit facility, and increasing the capacity of existing letter of credit facilities to support future liquidity and collateral needs. As a result of our review and discussions with potential lenders, we may elect to pursue alternative capital structures, including holding our Sithe and LS Entity assets under DHI, to be implemented in connection with the Merger Agreement with the LS Entities. Such alternative capital structures, if they are implemented, could affect our earnings and cash flows in 2007 and beyond.

Focus on Operational Excellence. We focus on improving our historically strong operating track record to achieve increased plant availability, higher dispatch and capacity factors, and improved cost controls. By managing fuel costs, minimizing plant outages and reducing corporate overhead, we aim to improve our ability to effectively capture revenue opportunities in the market place. Moreover, we commit to operating our facilities in a safe, reliable and environmentally compliant manner.

Tightly Manage Costs and Expenditures. We manage costs and capital expenditures effectively. Likewise, our power generation facilities are managed to require a relatively predictable level of maintenance capital expenditures without compromising operational integrity. We believe these ongoing efforts should allow us to maintain focus on being a reliable, low-cost producer of power.

Position for Regional Market Recovery. We operate a balanced portfolio of generation assets that is diversified in terms of geography, fuel type and dispatch profile. As a result, we believe our substantial coal-fired, baseload fleet should continue to benefit from the impact of higher natural gas prices on power prices in the Midwest and Northeast, allowing it to capture greater margins. It is anticipated that, following the consummation of the Merger Agreement with the LS Entities, the combined cycle units should provide meaningful cash flows and should benefit from improved margins as demand increases in the Western and Northeast markets.

Please read Item 1A. Risk Factors beginning on page 18 of our 2006 Form 10-K for additional factors that could impact our future operating results, financial condition and cash flows.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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 and working capital needs. Examples of working capital needs include prepayments or cash collateral associated with purchases of commodities, particularly natural gas, coal and fuel oil, facility maintenance costs and other costs such as payroll. Our liquidity and capital resources are primarily derived from cash flows from operations, cash on hand, borrowings under our financing agreements, proceeds from asset sales and proceeds from capital market transactions.

Debt Obligations

During 2006, we continued our efforts to enhance our capital structure flexibility, reduce our outstanding debt and extend our maturity profile. Repayments of long-term debt totaled $1,930 million for the year ended December 31, 2006 and consisted of the following payments:

•

$900 million in aggregate principal amount on our 10.125% Second Priority Senior Secured Notes due 2013;

•

$614 million in aggregate principal amount on our 9.875% Second Priority Senior Secured Notes due 2010;

•

$225 million in aggregate principal amount on our 2008 Notes;

•

$150 million in aggregate principal amount on our Term Loan due 2012;

•

$23 million in aggregate principal amount on our 7.45% Senior Notes due 2006; and

•

$18 million in aggregate principal amount on our 8.50% secured bonds due 2007.

In addition to the above repayments, we redeemed all of the outstanding shares of our Series C Preferred for $400 million and we completed an offer to convert all $225 million of our outstanding 4.75% Convertible Subordinated Debentures due 2023 into shares of our Class A common stock and cash. Further, we issued $297 million principal amount of additional 8.375% Senior Unsecured Notes due 2016 in exchange for all $419 million of outstanding Independence subordinated debt.

These repayments were partially offset by $1,071 million of proceeds from the following sources, net of approximately $29 million of debt issuance costs:

•

$750 million aggregate principal amount from a private offering of our 8.375% Senior Unsecured Notes due 2016;

•

$200 million, letter of credit facility due 2012; and

•

$150 million, term loan due 2012.

Following these transactions, our debt maturity profile as of December 31, 2006 includes $68 million in 2007, $44 million in 2008, $57 million in 2009, $73 million in 2010, $561 million in 2011 and approximately $2,455 million thereafter. Maturities for 2007 represent principal payments on the Independence Senior Notes and our 7.45% DHI Senior Notes

included in Notes payable and current portion of long-term debt on our consolidated balance sheets. Scheduled maturities of debt expected to be acquired in the Merger Agreement with the LS Entities are: $14 million in 2007, $14 million in 2008, $164 million in 2009, $16 million in 2010, $18 million in 2011 and approximately $2077 million thereafter. Please read Note 3—Business Combinations and Acquisitions—LS Power beginning on page F-17 for further discussion.

Summarized Debt and Other Obligations. The following table depicts our consolidated third party debt obligations, including the principal-like maturities associated with the DNE leveraged lease, and the extent to which they are secured as of December 31, 2006 and 2005:


	December 31, 2006			December 31, 2005
	(in millions)
First Secured Obligations
Dynegy Holdings Inc.	$	200		$	—
Sithe Energies (1)		448			885

Total First Secured Obligations		648			885
Second Secured Obligations		11			1,750
Unsecured Obligations		3,375			2,571

Subtotal		4,034			5,206
Preferred Obligations		—			400

Total Obligations	$	4,034		$	5,606

Less: DNE Lease Financing (2)		(801	)		(785	)
Less: Preferred Obligations		—			(400	)
Other (3)		25			(122	)

Total Notes Payable and Long-term Debt (4)	$	3,258		$	4,299

(1)	Please read Note 3—Business Combinations and Acquisitions—Sithe Energies beginning on page F-18 for further discussion.

(2)	Represents present value of future lease payments discounted at 10%.

(3)	Consists of net premiums on debt of $25 million and net discounts on debt of $122 million at December 31, 2006 and 2005, respectively.

(4)	Does not include letters of credit.

Collateral Postings

We continue to use a significant portion of our capital resources, in the form of cash 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. We manage the level of our collateral postings by line of business, rather than by reportable segment. This is primarily because collateral postings are generally determined on a counterparty basis, and our counterparties conduct business across reportable segments. The following table summarizes our consolidated collateral postings to third parties by line of business at February 22, 2007, December 31, 2006 and December 31, 2005:


	February 22, 2007		December 31, 2006		December 31, 2005
	(in millions)
By Business:
Generation business	$	178	$	134	$	280
Customer risk management business		50		54		91
Other		7		7		10

Total	$	235	$	195	$	381

By Type:
Cash (1)	$	40	$	38	$	122
Letters of credit		195		157		259

Total	$	235	$	195	$	381

(1)	Cash collateral consists of either cash deposits to cover physical deliveries or liabilities on mark-to-market positions or prepayments for commodities or services that are in advance of normal payment terms.

The increase in collateral postings from December 31, 2006 to February 22, 2007 is primarily due to increased fuel purchases and collateral postings just ahead of monthly commodity settlements.

The decrease in collateral postings from December 31, 2005 to December 31, 2006 is primarily due to a return of collateral postings of approximately $146 million in our generation business and $37 million in our customer risk management business. This decrease is primarily a result of decreases in commodity prices since the end of 2005 as well as the expiration of certain hedging positions. In addition, the $44 million of collateral posted on behalf of West Coast Power was returned as a result of the sale of our 50% interest in West Coast Power to NRG, completed on March 31, 2006.

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. In addition, the contemplated merger with the LS Entities and the effect of the Illinois resource procurement auction will have a significant impact on our exposure to collateral demands. We believe that we have sufficient capital resources to satisfy counterparties’ collateral demands, including those for which no collateral is currently posted, for the foreseeable future. Over the longer term, we expect to achieve incremental collateral reductions associated with the completion of our exit from the customer risk management business.

Disclosure of Contractual Obligations and Contingent Financial Commitments

We incur contractual obligations and financial commitments in the normal course of our operations and financing activities. Contractual obligations include future cash payments required under existing contracts, 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 operating activities. Financial commitments represent contingent obligations, such as financial guarantees, that become payable only if specified events occur. Details on these obligations are set forth below.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2006. Cash obligations reflected are not discounted and do not include accretion or dividends.


	Payments Due by Period
	Total		2007		2008		2009		2010		2011		Thereafter
Long-term debt (including current portion)	$	3,258	$	68	$	44	$	57	$	73	$	561	$	2,455
Interest payments on debt		2,019		283		260		253		248		205		770
Operating leases		1,476		139		164		164		117		133		759
Capital leases		16		2		2		2		2		2		6
Capacity payments		688		77		76		77		78		80		300
Conditional purchase obligations		114		12		11		11		12		13		55
Pension funding obligations		63		25		29		9		—		—		—
Other obligations		28		5		5		5		5		—		8

Total contractual obligations	$	7,662	$	611	$	591	$	578	$	535	$	994	$	4,353

The table above does not include amounts of long-term debt or other contractual obligations that are expected to be assumed as a result of the proposed Merger Agreement with the LS Entities. Please read Note 3—Business Combinations and Acquisitions—LS Power beginning on page F-17 for further discussion.

Long-Term Debt (Including Current Portion). Total amounts of Long-term debt (including current portion) are included in the December 31, 2006 consolidated balance sheet. For additional explanation, please read Note 12—Debt beginning on page F-36.

Operating Leases. Operating leases includes the minimum lease payment obligations associated with our DNE leveraged lease. For additional information, please read “—Liquidity and Capital Resources—Off-Balance Sheet Arrangements—DNE Leveraged Lease” beginning on page 45 of our 2006 Form 10-K. 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 VLGCs previously utilized in our global liquids business. The aggregate minimum base commitments of the charter party agreements are approximately $14 million each year for the years 2007 through 2009, and approximately $51 million 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 $51 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 August 2013 and August 2014, respectively. On January 1, 2003, in connection with the sale of our global liquids business, we 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.

Capital Leases. In January 2006, we entered into an obligation under a capital lease related to a coal loading facility which will be used in the transportation of coal to our Vermilion generating facility. Pursuant to our agreement with the lessor, we are obligated for minimum payments in the aggregate amount of $16 million over the remaining term of the lease.

Capacity Payments. Capacity payments include future payments aggregating $416 million under the Kendall power tolling arrangement, as further described in Item 1. Business—Segment Discussion—Customer Risk Management beginning on page 12 of our 2006 Form 10-K.

In November 2004, we entered into a “back-to-back” power purchase agreement under which a subsidiary of Constellation receives our rights to capacity and energy under the Kendall power tolling arrangement for a four-year term expiring in November 2008. Although we are still obligated under the Kendall toll, as of December 31, 2006, we will receive approximately $81 million in aggregate cash payments from Constellation to offset our fixed payment obligations under the Kendall toll through November 2008, which payment obligations are reflected in the table above. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Kendall on page F-22 for further discussion.

In addition, capacity payments include fixed obligations associated with transmission, transportation and storage arrangements totaling approximately $272 million.

Conditional Purchase Obligations. Amounts relate to our co-sourcing agreement with Accenture LLP for employee and infrastructure outsourcing. In early 2006, we amended the agreement to reduce our annual rate and to extend the term through 2016. We are obligated for minimum payments of approximately $114 million over the term of the agreement. This amended agreement may be cancelled at any time upon the payment of a termination fee not to exceed $1.7 million. This termination fee is in addition to amounts due for services provided through the termination date.

Pension Funding Obligations. Amounts include estimated defined benefit pension funding obligations for 2007 ($25 million), 2008 ($29 million) and 2009 ($9 million). Although we expect to continue to incur funding obligations subsequent to 2009, such amounts have not been included in this table because our estimates are imprecise.

Other Obligations. Other obligations include amounts related to a long-term coal agreement to assist in the delivery of coal to our Danskammer plant in Newburgh, New York. The agreement extends until 2010, and the minimum aggregate payments through expiration total approximately $10 million as of December 31, 2006. In addition, included in other obligations are payments associated with a capacity contract between Independence and Con Edison. The aggregate payments through the 2014 expiration are approximately $18 million as of December 31, 2006. Please read Note 3—Business Combinations and Acquisitions—Sithe Energies beginning on page F-18 for more information on this agreement.

Contingent Financial Obligations

The following table provides a summary of our contingent financial obligations as of December 31, 2006 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)	$	157	$	121	$	36	$	—	$	—
Surety Bonds (2) (3)		21		21		—		—		—
Guarantees (4)		4		—		4		—		—
Kendall guarantee (4)		200		200		—		—		—

Total Financial Commitments	$	382	$	342	$	40	$	—	$	—

(1)	Amounts include outstanding letters of credit.

(2)	Surety bonds are generally on a rolling 12-month basis. The $21 million of surety bonds were supported by collateral.

(3)

As part of the power purchase agreement with Constellation, under which Constellation effectively receives our rights to purchase approximately 570 MW of capacity and energy arising from our tolling contract with Kendall, we have guaranteed Constellation the receipt of $3.5 million in reactive power revenues over the four-year period of the power purchase agreement which ends November 2008. Our receipt of these reactive power revenues to offset this obligation is predicated on, among other things, filing a reactive power tariff with the FERC.

(4)

On September 14, 2006, certain of the LS Entities and Kendall Power LLC (“Kendall Power”), a newly formed wholly-owned subsidiary of Dynegy, entered into a Limited Liability Company Membership Interests and Stock Purchase Agreement (the “Kendall Agreement”) pursuant to which Kendall Power agreed to acquire all of the outstanding interests in LSP Kendall Holdings, LLC for $200 million in cash, as adjusted for certain changes in working capital. The closing of the Kendall Agreement will occur only if the closing of the Merger Agreement does not occur. We have agreed to guarantee certain of Kendall Power’s obligations under the Kendall Agreement. Please read Note 17—Commitments and Contingencies—Guarantees and Indemnifications—Kendall Guarantee on page F-51 for further discussion.

The table above does not include contingent financial obligations that are expected to be assumed as a result of the proposed Merger Agreement with the LS Entities.

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 for approximately $920 million 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, 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 was 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 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, 2006, future lease payments are $108 million for 2007, $144 million for 2008, $141 million for 2009, $95 million for 2010, $112 million for 2011 and $179 million for 2012, with $533 million in the aggregate due from 2013 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, 2006, the present value (discounted at 10%) of future lease payments was $801 million.

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


	2006		2005		2004
	(in millions)
Lease Expense	$	50	$	50	$	50
Lease Payments (Cash Flows)	$	60	$	60	$	60

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 redeem 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, 2006, the termination payment at par would be approximately $1 billion for all of the DNE facilities, which exceeds the $920 million we received on the sale of the facilities. If a termination of this type were to occur with respect to all of the DNE 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.

For further discussion of the accounting and required disclosure surrounding the subsidiaries that issued the pass-through certificates and purchased the notes from the owner lessors, please read Note 10—Unconsolidated Investments—Variable Interest Entities beginning on page F-33.

Capital Expenditures

We continue to tightly manage our operating costs and capital expenditures. We had approximately $155 million in capital expenditures during 2006. Our 2006 capital spending by reportable segment was as follows (in millions):


GEN-MW	$	101
GEN-NE		22
GEN-SO		24
Other		8

Total	$	155

Capital spending in our GEN-MW segment primarily consisted of maintenance capital projects, as well as approximately $2 million spent on development capital. Development capital spending primarily related to the conversion of our Vermilion facility to PRB coal. Capital spending in our GEN-NE and GEN-SO segments primarily consisted of maintenance and environmental projects.

We expect capital expenditures for 2007 to approximate $415 million, including the capital expenditures that may be associated with the LS Entities. This primarily includes maintenance capital projects, environmental projects and limited development projects. The capital budget is subject to revision as opportunities arise or circumstances change.

Our capital expenditures in 2007 and beyond will continue to be limited by negative covenants contained in our debt instruments. These covenants place specific dollar limitations on our ability to incur capital expenditures. Please read Note 12—Debt beginning on page F-36 for further discussion of these limitations. Our long term capital expenditures in the GEN-MW segment will also be significantly impacted by the DMG consent decree which obligates us to, among other things, install additional emission controls at our Baldwin and Havana plants which, based on ongoing engineering estimates, is expected to cost approximately $675 million from 2007 through 2012.

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 leverage ratios and other financial covenants, 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 credit ratings or 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.

Commitments and Contingencies

Please read Note 17—Commitments and Contingencies beginning on page F-47, which is incorporated herein by reference, for a discussion of our commitments and contingencies.

Dividends on Common Stock

Dividend payments on our common stock are at the discretion of our Board of Directors. We have not paid a dividend on our common stock since 2002, and we did not declare or pay a dividend on our common stock for the year ended December 31, 2006 and do not foresee a declaration of dividends in the near term due to the dividend restrictions contained in our financing agreements.

Internal Liquidity Sources

Our primary internal liquidity sources are cash flows from operations and cash on hand.

Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at February 22, 2007, December 31, 2006 and December 31, 2005:


	February 22, 2007			December 31, 2006			December 31, 2005
	(in millions)
Total revolver capacity	$	470		$	470		$	—
Total additional letter of credit capacity		194			194			325	(1)
Outstanding letters of credit under credit facility		(195	)		(157	)		(259	)

Unused credit facility capacity		469			507			66
Cash		372	(2)		371	(2)		1,549	(2)(3)

Total available liquidity	$	841		$	878		$	1,615

(1)

On April 19, 2006, we entered into a fourth amended and restated credit agreement which consists of (i) a $470 million revolving credit component and (ii) a $200 million letter of credit component. Please read Note 12—Debt—Fourth Amended and Restated Credit Facility beginning on page F-36 for further discussion of our amended credit facility. Our credit facility capacity is limited by, and will increase or decrease with changes in cash collateral on deposit.

(2)	The February 22, 2007, December 31, 2006 and December 31, 2005 amounts include approximately $41 million, $46 million, and $21 million, respectively, of cash that remains in the Europe and $18 million, $10 million and $19 million, respectively, of cash that remains in the Canada.

(3)	The December 31, 2005 amount includes approximately $13 million of cash held by our NGL business. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Natural Gas Liquids beginning on page F-23.

Cash Flows from Operations. We had operating cash outflows of $194 million for the year ended December 31, 2006. This consisted of $698 million in operating cash flows from our power generation business, reflecting positive earnings for the period and increases in working capital due to returns of cash collateral postings. These cash flows were offset by $892 million of cash outflows relating to our customer risk management business and corporate-level expenses. Please read “—Results of Operations—Operating Income” and “—Cash Flow Disclosures” for further discussion of factors impacting our operating cash flows for the periods presented.

Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of natural gas and its correlation to power prices, the cost of coal and fuel oil and the value of ancillary services. Additionally, the availability of our plants during peak demand periods will be required to allow us to capture attractive market prices when available. Over the longer term, our operating cash flows also will be impacted by, among other things, our ability to tightly manage our operating costs, including maintenance costs. Our ability to achieve targeted cost savings in the face of industry-wide increases in labor and benefits costs, together with changes in commodity prices, will impact our future operating cash flows. Please read “—Results of Operations—2007 Outlook” beginning on page 63 of our 2006 Form 10-K for further discussion.

Cash on Hand. At February 22, 2007 and December 31, 2006, we had cash on hand of $372 million and $371 million, respectively, as compared to $1,549 million at the end of 2005. This decrease in cash on hand at February 22, 2007 and December 31, 2006 as compared to the end of 2005 is primarily attributable to cash used for debt repayments, litigation settlements and capital expenditures.

Revolver Capacity. On April 19, 2006, we entered into the Fourth Amended and Restated Credit Facility, replacing the former Third Amended and Restated Credit Facility with a $470 million revolving credit facility, thereby providing the return to DHI of $335 million plus accrued interest in cash collateral securing the former Third Amended and Restated Credit Facility. As of February 22, 2007, $195 million in letters of credit are outstanding but undrawn, and we have no revolving loan amounts drawn under the Fourth Amended and Restated Credit Facility. Please read Note 12—Debt—Fourth Amended and Restated Credit Facility beginning on page F-36 for further discussion of our amended credit facility.

External Liquidity Sources

Our primary external liquidity sources are proceeds from asset sales and other types of capital-raising transactions, including public or private equity issuances.

Asset Sale Proceeds. In March 2006, we completed our ownership exchange transactions with NRG which comprised our acquisition of NRG’s 50% ownership interest in the entity that owns the Rocky Road power plant (of which we already owned 50%), and the sale to NRG of our 50% ownership interest in the West Coast Power plant, a joint venture between us and NRG, which has ownership in power plants in southern California. As a result of the two transactions, we received cash proceeds of approximately $165 million, net of cash acquired, from NRG. Please read Note 3—Business Combinations and Acquisitions—Rocky Road on page F-18 for further discussion. Also, please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—West Coast Power on page F-20 for further discussion.

In November 2006, we completed our sale to Duke Energy Carolinas, LLC (a subsidiary of Duke Energy) (“Duke Power”) of our Rockingham facility, a peaking facility in North Carolina, which is included in our GEN-SO reportable segment, for $194 million in cash. A portion of the proceeds from the sale were used to repay our borrowings under the $150 million Term Loan, with the remaining proceeds used as an additional source of liquidity. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Rockingham on page F-20 for further discussion. Please read Note 12—Debt—Fourth Amended and Restated Credit Facility on page F-36 for further discussion of the Term Loan.

On January 31, 2007, we entered into an agreement to sell our interest in the Calcasieu power generation facility to Entergy for approximately $57 million, subject to regulatory approval. The transaction is expected to close in early 2008. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Calcasieu on page F-23 for further discussion.

We are continuing to evaluate our generation fleet based primarily on geographic location, fuel supply, market structure and market recovery expectations. This evaluation will consider the combined portfolio of Dynegy and the LS Entities in anticipation of the pending transaction. Consistent with industry practice, we periodically consider divestitures of non-core generation assets where the balance of the factors described above suggests that such assets’ earnings potential is limited or that the value that can be captured through a divestiture outweighs the benefits of continuing to own and operate such assets. In conducting our current portfolio review, we are considering, among other things, divesting certain assets that (i) are primarily peaking in nature and generally operate in locations where market recovery is projected to occur much further in the future than in other regions in which we will have a significant asset position, or (ii) could present value propositions through potential dispositions not likely to be achieved through continued ownership and operation by us. As a result of this review, we are considering selling our 614 MW Cogen Lyondell generation facility, our 576 MW Bluegrass generation facility and our 539 MW Heard County generation facility. Moreover, dispositions of one or more other generation facilities could occur in 2007 or beyond. Were any such sale or disposition to be consummated, the disposition could result in accounting charges related to the affected asset(s), and our earnings and cash flows could be affected in 2007 and beyond.

Capital-Raising Transactions. As part of our ongoing efforts to maintain a capital structure that is closely aligned with the cash-generating potential of our asset-based business, which is subject to cyclical changes in commodity prices, we will continuously explore additional sources of external liquidity both in the near- and long-term. The timing of any transaction may be impacted by events, such as strategic growth opportunities, legal judgments or regulatory requirements, which could require us to pursue additional capital in the near-term. In particular, in connection with the pending transaction with the LS Entities, we will be evaluating various opportunities to provide additional liquidity and streamline the combined company’s capital structure.

These transactions may include capital markets transactions. The receptiveness of the capital markets to a public offering cannot be assured and may be negatively impacted by, among other things, our non-investment grade credit ratings, significant debt maturities, long-term business prospects and other factors beyond our control. Any issuance of equity likely would have other effects as well, including shareholder dilution. Further, our ability to issue debt securities is limited by our financing agreements, including our Fourth Amended and Restated Credit Facility. Please read Note 12—Debt—Fourth Amended and Restated Credit Facility beginning on page F-36 for further discussion.

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 2006, 2005 and 2004. At the end of this section, we have included our business outlook for each segment.

We report the results of our power generation business as three separate segments in our consolidated financial statements: (1) the Midwest segment (GEN-MW); (2) the Northeast segment (GEN-NE); and (3) the South segment (GEN-SO). We also separately report the results of our CRM business, which primarily consists of the Kendall tolling agreement, the remaining power tolling arrangement (excluding the Sithe toll which is now in our GEN-NE segment and is an intercompany agreement), as well as legacy natural gas, power and emissions trading positions. Because of the diversity among their respective operations, 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 and interest. Beginning January 1, 2006, all direct general and administrative expenses are included in Other and Eliminations unless they are specifically identified with the respective segment. This change in allocation methodology is a result of our efforts to better align our corporate cost structure with a single line of business.

As described below, substantially all of our NGL business, which was conducted through DMSLP and its subsidiaries and comprised our NGL reportable segment, was sold to Targa on October 31, 2005. Additionally, as described below, our former REG business, which was conducted through Illinois Power and its subsidiaries and comprised our REG reportable segment, was sold to Ameren Corporation on September 30, 2004.

Summary Financial Information. The following tables provide summary financial data regarding our consolidated and segmented results of operations for 2006, 2005 and 2004, respectively.


	Year Ended December 31, 2006
	Power Generation
	GEN-MW		GEN - NE		GEN-SO			CRM		Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	208	$	55	$	(16	)	$	7	$	(163	)	$	91
Losses from unconsolidated investments		—		—		(1	)		—		—			(1	)
Other items, net		2		9		1			4		38			54
Interest expense and debt conversion costs														(631	)

Loss from continuing operations before taxes														(487	)
Income tax benefit														154

Loss from continuing operations														(333	)
Loss from discontinued operations, net of taxes														(1	)
Cumulative effect of change in accounting principle, net of taxes														1

Net loss													$	(333	)


	Year Ended December 31, 2005
	Power Generation
	GEN-MW		GEN - NE		GEN-SO			CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	194	$	29	$	(18	)	$	(647	)	$	(393	)	$	(835	)
Earnings (losses) from unconsolidated investments		7		—		(5	)		—			—			2
Other items, net		2		5		(1	)		—			20			26
Interest expense															(389	)

Loss from continuing operations before taxes															(1,196	)
Income tax benefit															394

Loss from continuing operations															(802	)
Income from discontinued operations, net of taxes															897
Cumulative effect of change in accounting principle, net of taxes															(5	)

Net income														$	90


	Year Ended December 31, 2004
	Power Generation
	GEN-MW		GEN-NE		GEN-SO			CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	194	$	21	$	(52	)	$	(118	)	$	(145	)	$	(100	)
Earnings from unconsolidated investments		80		—		112			—			—			192
Other items, net		—		—		1			(3	)		11			9
Interest expense															(453	)

Loss from continuing operations before taxes															(352	)
Income tax benefit															172

Loss from continuing operations															(180	)
Income from discontinued operations, net of taxes															165

Net loss														$	(15	)

The following table provides summary segmented operating statistics for 2006, 2005 and 2004, respectively:


	Year Ended December 31,
	2006		2005		2004
GEN-MW
Million Megawatt Hours Generated—Gross and Net		21.5		21.9		22.6
Average Actual On-Peak Market Power Prices ($/MWh) (1):
Cinergy (Cin Hub)	$	52	$	64	$	43
Commonwealth Edison (NI Hub)	$	52	$	62	$	42

GEN-NE
Million Megawatt Hours Generated—Gross and Net		4.4		8.3		6.0
Average Actual On-Peak Market Power Prices ($/MWh) (1):
New York—Zone G	$	76	$	92	$	62
New York—Zone A	$	59	$	76	$	53

GEN-SO
Million Megawatt Hours Generated—Gross		4.6		7.3		8.5
Million Megawatt Hours Generated—Net		3.9		5.3		6.7
Average Actual On-Peak Market Power Prices ($/MWh) (1):
Southern	$	55	$	71	$	49
ERCOT	$	63	$	80	$	51
SP-15	$	62	$	73	$	55

Average natural gas price—Henry Hub ($/MMBtu) (2)	$	6.74	$	8.80	$	5.85

(1)	Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices realized by the company.

(2)	Reflects the average of daily quoted prices for the periods presented and does not necessarily reflect prices realized 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, 2006
	Power Generation
	GEN-MW			GEN-NE			GEN-SO			CRM			Other and Eliminations			Total
	(in millions)
Debt conversion costs	$	—		$	—		$	—		$	—		$	(249	)	$	(249	)
Asset impairments		(110	)		—			(9	)		—			—			(119	)
Legal and settlement charges		—			—			—			(53	)		—			(53	)
Sithe Subordinated Debt exchange charge		—			(36	)		—			—			—			(36	)
Acceleration of financing costs		—			—			—			—			(36	)		(36	)
Taxes		—			—			—			—			(29	)		(29	)
Discontinued operations (1)		—			—			(39	)		23			7			(9	)

Total	$	(110	)	$	(36	)	$	(48	)	$	(30	)	$	(307	)	$	(531	)

(1)	Discontinued operations includes an impairment of $36 million associated with the Calcasieu natural gas-fired peaking facility.


	Year Ended December 31, 2005
	Power Generation
	GEN-MW			GEN-NE		GEN-SO			CRM			Other and Eliminations			Total
	(in millions)
Discontinued operations (1)	$	—		$	—	$	(3	)	$	6		$	1,250		$	1,253
Sterlington toll settlement		—			—		—			(364	)		—			(364	)
Legal and settlement charges		—			—		—			(38	)		(249	)		(287	)
Independence toll settlement charge		—			—		—			(169	)		—			(169	)
Asset impairment		(29	)		—		—			—			—			(29	)
Impairment of generation investments		—			—		(27	)		—			—			(27	)
Restructuring costs		—			—		—			—			(11	)		(11	)
Taxes		—			—		—			—			89			89

Total	$	(29	)	$	—	$	(30	)	$	(565	)	$	1,079		$	455

(1)	Discontinued operations for NGL includes gain on sale of DMSLP of $1,087 million.


	Year Ended December 31, 2004
	Power Generation
	GEN-MW			GEN-NE		GEN-SO			CRM			Other and Elimination			Total
	(in millions)
Discontinued operations (1)	$	—		$	—	$	—		$	19		$	257		$	276
Kendall toll restructuring		—			—		—			(115	)		—			(115	)
Legal and settlement charges		(9	)		—		2			(13	)		(93	)		(113	)
Impairment of West Coast Power		—			—		(85	)		—			—			(85	)
Loss on sale of Illinois Power		—			—		—			—			(58	)		(58	)
Impairment of Illinois Power		—			—		—			—			(54	)		(54	)
Acceleration of financing costs		—			—		—			—			(14	)		(14	)
Gas transportation contracts		—			—		—			88			—			88
Gain on sale of Joppa		75			—		—			—			—			75
Taxes		—			—		—			—			24			24
Gain on sale of Oyster Creek		—			—		15			—			—			15

Total	$	66		$	—	$	(68	)	$	(21	)	$	62		$	39

(1)	Discontinued operations for NGL includes pre-tax gains on sales of Indian Basin, Hackberry LNG and Sherman totaling $36 million, $17 million and $16 million, respectively.

Year Ended 2006 Compared to Year Ended 2005

Operating Income (Loss)

Operating income was $91 million for the year ended December 31, 2006, compared to an operating loss of $835 million for the year ended December 31, 2005.

Power Generation—Midwest Segment. Operating income for GEN-MW was $208 million for the year ended December 31, 2006, compared to $194 million for the year ended December 31, 2005. GEN-MW results for 2006 include a $110 million pre-tax impairment associated with our Bluegrass facility. GEN-MW results for 2005 include a $29 million pre-tax charge associated with the impairment of a natural gas turbine which was sold in 2006. GEN-MW results for the year ended December 31, 2005 also included general and administrative expenses of $33 million. Beginning in 2006, general and administrative expenses are reported in Other and Eliminations. Please read “Results of Operations—Year Ended 2006 Compared to Year Ended 2005—Operating Income (Loss)—Other” for a consolidated discussion of general and administrative expenses.

Results from our coal-fired generating units increased from $415 million for the year ended December 31, 2005 to $466 million for 2006. Average actual on-peak prices in the CinHub/Cinergy pricing region decreased from $64 per MWh in the year ended December 31, 2005 to $52 per MWh for the year ended December 31, 2006. Generated volumes decreased from 21.9 million MWh in the year ended December 31, 2005 to 21.5 million MWh in the same period in 2006. Despite the decrease in market prices and the decrease in output, the increase in results was primarily driven by higher realized power prices. We realized higher power prices in the first quarter 2006 as we settled forward power sales. Additionally, results from our coal-fired generating units were negatively impacted by the AmerenIP contract during the second and third quarters of 2005, preventing us from recognizing the full benefit of market prices during the 2005 period. During certain peak periods in 2005, Ameren took higher volumes than we expected, resulting in a need to purchase power at market prices in order to satisfy our obligations for forward sales previously made to other third-parties. We did not experience a similar situation under the AmerenIP contract in 2006. This was offset by mark-to-market income of approximately $14 million for the year ended December 31, 2006, compared with mark-to-market income of $23 million for the year ended December 31, 2005. These transactions are primarily related to options and other financial transactions that economically hedged our generation assets but were not designated as cash flow hedges. The higher realized prices were also partially offset by higher operating costs due to the timing of scheduled maintenance.

Results for our natural gas-fired peaking facilities in GEN-MW improved by $13 million, increasing from $7 million for 2005 to $20 million for the same period in 2006. This improvement was the result of our acquisition of the remaining ownership interest in the Rocky Road facility and the related increase in capacity fees. This increase was partially offset by lower pricing and volumes. Additionally, our 2005 results included a $5 million charge associated with the write-down of spare parts inventory.

Depreciation expense increased from $157 million in 2005 to $168 million in 2006 as a result of our acquisition of the remaining ownership interest in the Rocky Road facility and capital projects placed into service in 2006. The capital projects were primarily related to the conversion of the Havana facility to burn PRB coal. Please read Note 5—Restructuring and Impairment Charges—Asset Impairments for further discussion. Our 2005 results also included a $7 million charge associated with the write-off of an environmental project.

Power Generation—Northeast Segment. Operating income for GEN-NE was $55 million for the year ended December 31, 2006, compared to $29 million for the year ended December 31, 2005. GEN-NE results for the year ended December 31, 2005 included general and administrative expenses of $22 million. Beginning in 2006, general and administrative expenses are reported in Other and Eliminations. Please read “Results of Operations—Year Ended 2006 Compared to Year Ended 2005—Operating Income (Loss)—Other” for a consolidated discussion of general and administrative expenses.

Results for our Roseton and Danskammer facilities decreased from $53 million in 2005 to $33 million in 2006 primarily as a result of lower prices and volumes. Average on-peak prices for Zone G, the market served by these two facilities, decreased from $92 per MWh in 2005 to $76 per MWh in 2006. Generated volumes decreased from 6.0 million MWh in 2005 compared to 2.7 million MWh in 2006. Compressed spark spreads for part of the year resulted in lower production of our Roseton facility, where volumes fell by 2.9 million MWH from 2005 to 2006. Additionally, the year ended December 31, 2006 included a fuel oil inventory write-down of approximately $6 million.

Independence contributed results of $46 million for the year ended December 31, 2006, compared with $18 million for the period from February through December 2005. Average on-peak prices for Zone A decreased from $76 per MWh in 2005 to $59 per MWh in 2006. Generated volumes decreased from 2.3 million MWh in 2005 to 1.7 million MWh in 2006. Although market prices and generated volumes from our Independence facility decreased year over year, we received a benefit from the realization of higher power prices in the first half of 2006, as we settled forward power sales. Results for 2006 also reflect the benefit of increased capacity payments in the merchant market.

Depreciation expense for GEN-NE increased from $21 million in 2005 to $24 million in 2006, as the result of acquiring the Independence facility in February 2005 as well as the result of capital projects placed into service in 2006.

Power Generation—South Segment. Operating loss for GEN-SO was $16 million for the year ended December 31, 2006, compared to an operating loss of $18 million for the year ended December 31, 2005. GEN-SO results for 2006 include a $9 million impairment of our Rockingham facility as a result of the sale of the facility. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Rockingham for further discussion. GEN-SO results for the year ended December 31, 2005 also included general and administrative expenses of $11 million. Beginning in 2006, general and administrative expenses are reported in Other and Eliminations. Please read “Results of Operations—Year Ended 2006 Compared to Year Ended 2005—Operating Income (Loss)—Other” for a consolidated discussion of general and administrative expenses.

Results from our ERCOT facility decreased by $8 million from $6 million in 2005 to a loss of $2 million in 2006, primarily driven by decreases in ancillary services revenue caused by a depressed ancillary services market in the ERCOT region during 2006. Also included in the 2006 results are $1 million of mark-to-market losses compared to zero in 2005.

Results from our other South assets increased from $5 million in 2005 to $14 million in 2006, primarily as a result of increased volumes and pricing for our peaking facilities.

Depreciation expense was $19 million in 2006 compared to $21 million in 2005.

Customer Risk Management. Operating income was $7 million for 2006, compared to an operating loss of $647 million for 2005. CRM’s 2006 results reflect charges of approximately $53 million in legal reserves resulting from additional activities during the period that negatively affected management’s assessment of probable and estimable losses associated with the applicable proceedings and settlements. These charges were partially offset by mark-to-market income on our legacy coal, natural gas, emissions, and power positions. CRM’s 2005 results were impacted by the following items:

•

$364 million charge associated with the agreement to terminate our Sterlington tolling arrangement.

•

$169 million charge associated with the Sithe Energies acquisition. Prior to the acquisition, Independence held a power tolling contract and a natural gas supply agreement with our CRM segment. Upon completion of the purchase, these contracts became intercompany agreements under our GEN-NE segment, and were effectively eliminated on a consolidated basis, resulting in the $169 million charge upon completion of the acquisition.

•

$74 million net losses related to our legacy power positions, primarily fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and sold.

•

$38 million charge related to increased legal reserves. The increased legal reserves resulted from additional activities during the year that affected management’s assessment of the probable and estimable loss associated with the applicable proceedings.

•

$26 million net mark-to-market losses from our legacy natural gas and emissions positions.

These losses were partly offset by a $21 million gain related to the termination of a contract to sell emissions allowances.

Other. Other operating loss was $163 million for 2006, compared to $393 million for 2005. Results include approximately $143 million of general and administrative expenses, including costs related to our business segments, which prior to 2006 were included in the individual segments. Results for 2005 included general and administrative expenses of $364 million.

Consolidated general and administrative expenses decreased from $468 million for 2005 to $196 million for 2006. General and administrative expenses for 2005 included a $236 million charge associated with settlement of our shareholder class action litigation and other legal settlement charges totaling $51 million, while 2006 included $53 million in additional legal reserves. Additionally, compensation and benefits costs and professional and legal fees were lower in 2006 compared to 2005.

Earnings from Unconsolidated Investments

The $1 million loss reported from unconsolidated investments for 2006 was primarily related to the GEN-SO investment in Black Mountain. During 2006, we recorded equity earnings of $8 million related to our investment in Black Mountain offset by a $9 million impairment charge. This charge is the result of a decline in value of the investment related to the high cost of fuel in relation to a third party power purchase agreement through 2023 for 100% of the output of the facility. This agreement provides that Black Mountain (Nevada Cogeneration) will receive payments that decrease over time. The $2 million earnings reported for 2005 included $7 million earnings from the GEN-MW investment in Rocky Road, largely offset by results from GEN-SO investments in both Black Mountain and West Coast Power.

Other Items, Net

Other items, net totaled $54 million of income for 2006, compared to $26 million of income for 2005. The increase was primarily associated with higher interest income in 2006 resulting from higher cash balances and higher interest rates.

Interest Expense

Interest expense and debt conversion costs totaled $631 million for 2006, compared to $389 million for 2005. The increase was primarily due to debt conversion and acceleration of financing costs, as well as a $36 million charge associated with the Sithe Subordinated Debt exchange. These charges were partially offset by reductions due to lower principal amounts outstanding as a result of our liability management program. Please read Note 12—Debt for further discussion

Income Tax Benefit

Our income tax benefit from continuing operations was $157 million in 2006, compared to an income tax benefit from continuing operations of $394 million in 2005. The 2006 effective tax rate was 32%, compared to 33% in 2005. The 2006 tax benefit included a $29 million expense related to various adjustments anticipated as a result of the Canadian authorities’ audit of prior year income tax returns. The 2005 tax benefit included an $18 million expense and a $13 million expense related to an increase in the valuation allowance associated with capital losses and foreign NOLs, respectively. Excluding these items from the 2006 and 2005 calculations would result in effective tax rates of 37% and 36% in 2006 and 2005, respectively. In general, differences between these adjusted effective rates and the statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and permanent differences attributable to book-tax basis differences.

Please read Note 14—Income Taxes beginning on page F-42 for further discussion of our income taxes.

Discontinued Operations

Income (Loss) From Discontinued Operations Before Taxes. Discontinued operations include Calcasieu in our GEN-SO segment, DMSLP in our former NGL segment, our U.K. CRM business, our former DGC segment and our U.K. natural gas storage assets from our CRM segment. The following summarizes the activity included in income from discontinued operations:

Year Ended December 31, 2006


	Calcasieu			U.K. CRM		DGC		NGL		Total
	(in millions)
Operating income (loss) included in loss from discontinued operations	$	(39	)	$	18	$	—	$	6	$	(15	)
Other items, net included in loss from discontinued operations		—			5		1		—		6

Loss from discontinued operations before taxes											(9	)
Income tax benefit											5

Loss from discontinued operations										$	(4	)

Year Ended December 31, 2005


	Calcasieu			U.K. CRM		NGL			Total
	(in millions)
Operating income (loss) included in income from discontinued operations	$	(3	)	$	—	$	1,320		$	1,317
Earnings from unconsolidated investments included in income from discontinued operations		—			—		5			5
Other items, net included in income from discontinued operations		—			6		(22	)		(16	)
Interest expense included in income from discontinued operations										(53	)

Income from discontinued operations before taxes										1,253
Income tax expense										(356	)

Income from discontinued operations									$	897

As further discussed in Note 4—Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Natural Gas Liquids beginning on page F-23, on October 31, 2005, we completed the sale of DMSLP. As a result of the sale, and as required SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144), we have reclassified the operations related to DMSLP, which comprised of the remaining operations of our NGL segment, from continuing operations to discontinued operations.

In 2006, pre-tax loss from discontinued operations of $9 million ($4 million after-tax) included $6 million in pre-tax income attributable to NGL and a pre-tax gain of $21 million associated with a receivable previously reserved in our U.K. CRM business. Additionally, pre-tax loss from discontinued operations includes a $36 million impairment associated with the Calcasieu natural gas-fired peaking facility. Please read Note 5—Restructuring and Impairment Charges—Asset Impairments on page F-24 for further discussion. In 2005, pre-tax income from discontinued operations of $1,253 million ($897 million after-tax) included $1,250 million in pre-tax income attributable to NGL. Included in NGL’s 2005 pre-tax income is a pre-tax gain on the sale of DMSLP of $1,087 million and income attributable to ten months of operations.

In accordance with EITF Issue 87-24, “Allocation of Interest to Discontinued Operations” (EITF Issue 87-24), we have allocated interest expense to discontinued operations associated with debt instruments that were required to be paid upon the sale of DMSLP. Interest expense included in income from discontinued operations, which includes interest incurred on our former term loan and our former Generation facility debt, totaled zero and $53 million during 2006 and 2005, respectively.

Income Tax Benefit (Expense) From Discontinued Operations. We recorded an income tax benefit from discontinued operations of $5 million in 2006, compared to an income tax expense from discontinued operations of $356 million in 2005. The income tax expense in 2005 includes a $112 million benefit associated with reducing a valuation allowance related to our capital loss carryforward, which primarily relates to our third quarter 2002 sale of Northern Natural Gas. We reduced the valuation allowance as a result of capital gains expected to be recognized from our sale of DMSLP. For further information regarding the sale, please see Note 4— Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Natural Gas Liquids. The effective rates for 2006 and 2005, adjusting for the reduction of the valuation allowance in 2005, are 56% and 38%, respectively.

Cumulative Effect of Change in Accounting Principles

On January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123(R)). In connection with its adoption, we realized a cumulative effect loss of approximately $1 million, net of tax expense of zero. For further information, please see Note 2—Summary of Significant Accounting Policies—Accounting Principles Adopted—SFAS No. 123(R) on page F-16.

On December 31, 2005, we adopted FIN No. 47. In connection with its adoption, we realized a cumulative effect loss of approximately $5 million ($7 million pre-tax). For further information, please see Note 2— Summary of Significant Accounting Policies—Asset Retirement Obligations beginning on page F-11.

Year Ended 2005 Compared to Year Ended 2004

Operating Loss

Operating loss was $835 million for the year ended December 31, 2005, compared to $100 million for the year ended December 31, 2004.

Power Generation—Midwest Segment. Operating income for GEN-MW was $194 million for the years ended December 31, 2005 and 2004.

Results from our coal-fired generating units increased from $392 million for the year ended December 31, 2004 to $415 million for 2005. Average on-peak prices in the NI Hub/Com Ed pricing region increased from $42 per MWh in 2004 to $62 per MWh for 2005. Additionally, volumes were up 3%, from 20.7 million MWh for 2004 to 21.3 million MWh. Despite the increases in volumes and price, results from our coal-fired generating units were negatively impacted by the AmerenIP contract, preventing us from recognizing the full benefit of the increase in market prices. Volumes sold pursuant to this contract with AmerenIP increased 25% in 2005 compared to 2004, resulting in a reduced supply of power available for sale at prevailing market prices in 2005. During certain peak periods, Ameren took higher volumes than we expected, resulting in a need to purchase power at market prices in order to satisfy our obligations. Volumes, excluding those sold under the AmerenIP contract, decreased by 1.7 million MWh from 2004 to 2005. Additionally, GEN-MW’s results for 2005 include $23 million of net mark-to-market income. As a result of increased power prices and overall power price volatility, we recognized $9 million of mark-to-market gains during 2005 associated with options sold during the period, and $8 million of mark-to-market gains associated with other financial transactions. Additionally, as of December 31, 2005, we recorded $5 million of income related to FTRs that were not designated as cash flow hedges. For the year ended December 31, 2004, our results included $16 million of mark-to-market losses, primarily related to options and other transactions that economically hedged our generation assets, and were not accounted for as cash flow hedges.

Results for our natural gas-fired peaking facilities in GEN-MW improved by $11 million, from a loss of $4 million for 2004 to earnings of $7 million for 2005. This improvement was a result of favorable power pricing, caused primarily by warm weather and generally higher fuel prices. These factors made it economical to produce substantially more power than our natural gas-fired facilities produced in 2004. However, our 2005 results also include a charge of $5 million related to the write-down of spare parts inventory.

General and administrative expense for GEN-MW decreased from $38 million in 2004 to $33 million in 2005 largely due to expenses associated with the DMG consent decree in 2004. Depreciation expense increased slightly, from $156 million in 2004 to $157 million in 2005. Improved 2005 results at both our coal and natural gas-fired facilities were offset by a $29 million charge associated with the impairment of a natural gas turbine, which was sold in 2006, as well as a $7 million charge associated with the write-off of an environmental project.

Power Generation—Northeast Segment. Operating income for GEN-NE was $29 million for the year ended December 31, 2005, compared to $21 million for the year ended December 31, 2004.

Results from our Roseton, Danskammer and Independence facilities were $71 million for 2005, compared with $44 million in 2004. Beginning in February 2005, GEN-NE’s results include earnings from the Independence facility. See Note 3—Business Combinations and Acquisitions—Sithe Energies beginning on page F-18 for further discussion of the acquisition of Independence. The addition of Independence and increased power prices were the primary driver of earnings in 2005. Average on-peak market prices increased from $62 per MWh in 2004 to $92 per MWh in 2005. Compressed spark spreads for part of the year resulted in lower production at our Roseton facility, where volumes fell by 0.5 million MWh from 2004 to 2005. However, during the times Roseton was running, spark spreads were higher than the previous year. Generated volumes at our Danskammer facility rose by 0.4 million MWh from 2004 to 2005. The benefit of increased spark spreads was partly offset by operating expense, which increased from $120 million in 2004 to $139 million in 2005, primarily as a result of the timing of maintenance projects, as well as an increase in labor costs. GEN-NE’s results included $12 million of mark-to-market losses and $17 million of mark-to-market gains in 2005 and 2004 respectively, related to financial transactions not designated as cash flow hedges.

General and administrative expense in GEN-NE increased from $13 million in 2004 to $22 million in 2005, primarily as a result of the addition of our Independence facility. Depreciation expense for GEN-NE increased from $10 million to $21 million, also as the result of the addition of the Independence facility.

Power Generation—South Segment. Operating loss for GEN-SO was $18 million for the year ended December 31, 2005, compared to a loss of $52 million for the year ended December 31, 2004.

Results from our ERCOT facility improved by $18 million, from a loss of $12 million for 2004 to income of $6 million for 2005. Power prices in the ERCOT region increased by 57% from 2004 to 2005, and we were also able to provide additional ancillary services to the market. Results from our peaker assets in the Southeast increased, from a loss of $8 million in 2004 to earnings of $5 million in 2005, as a result of improved spark spreads in the region.

Included in the 2004 results discussed above are $8 million of mark-to-market losses, $3 million of which relates to hedge ineffectiveness in the ERCOT region, and $5 million of which relates to financial transactions not designated as cash flow hedges.

General and administrative expense was $11 million in both 2004 and 2005. Depreciation expense decreased slightly, from $22 million in 2004 to $21 million for 2005.

Customer Risk Management. Operating loss for the CRM segment was $647 million for 2005. Results for 2005 were impacted by the following items:

•

$364 million charge associated with the agreement to terminate our Sterlington tolling arrangement.

•

$74 million net losses related to our legacy power positions, primarily fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and sold.

•

$26 million net mark-to-market loss from our legacy natural gas and emissions positions.

•

These losses were partly offset by a $21 million gain related to the termination of a contract to sell emissions allowances.

Results for 2004 were impacted by the following items:

•

$88 million gain associated with the exit of four natural gas transportation agreements in support of our third party marketing business; offset by

•

$115 million charge associated with our entry into a “back-to-back” power purchase agreement with a subsidiary of Constellation in November 2004 to mitigate the effect of the Kendall tolling arrangement through November 2008.

CRM’s results for 2004 also reflect the impact of fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and sold and include $10 million in gains associated with the mark-to-market value of certain legacy natural gas contracts which had previously been accounted for on an accrual basis.

Other. During 2004, results included operating income of $139 million related to our former REG business. This includes a $58 million charge related to the sale of Illinois Power and a $54 million charge for the impairment of assets.

Finally, results for 2005 include a $236 million charge associated with the settlement of our shareholder class action litigation and other legal settlement charges totaling $13 million. Results for 2005 also include an $11 million charge associated with our December 2005 restructuring. Results for 2004 include approximately $92 million of expenses related to legal and settlement charges. The legal charges resulted from additional activities during the period that affected management’s assessment of the probable and estimable loss associated with the applicable proceedings. In addition, 2005 results benefited from lower compensation, insurance and external consultant costs compared to the same period in 2004.

Earnings from Unconsolidated Investments

Total earnings from unconsolidated investments were $2 million for the year ended December 31, 2005, compared to $192 million for the year ended December 31, 2004.

Power Generation—Midwest Segment. Earnings from unconsolidated investments for GEN-MW were $7 million for the year ended December 31, 2005, compared to $80 million for the year ended December 31, 2004. Both periods included $7 million of earnings related to our Rocky Road investment, which we then owned jointly with NRG Energy. 2004 earnings also included a gain of $75 million related to our sale of our 20% interest in the Joppa power generation facility. Additionally, 2004 earnings included an $8 million impairment related to the sale of our 50% interest in the Michigan Power generating facility, which, when netted against our earnings from the investment for 2004, resulted in a $2 million net loss.

Power Generation—South Segment. Losses from unconsolidated investments for GEN-SO were $5 million for 2005, compared with earnings of $112 million for 2004.

For 2005, our 50% interest in our investment in Black Mountain (Nevada Cogeneration) reported earnings of $5 million; however, these earnings were more than offset by a $13 million impairment charge. This charge is the result of a decline in value of the investment related to the high cost of fuel in relation to a third party power purchase agreement through 2023 for 100% of the output of the facility. This agreement provides that Black Mountain (Nevada Cogeneration) will receive payments that decrease over time. Additionally, in 2005 we recorded a $10 million impairment charge related to our investment in West Coast Power, related to the sale of our 50% interest in the investment to our partner, NRG. This charge almost completely offset the $11 million of 2005 earnings from the investment. Finally, 2005 earnings include $6 million of earnings from our investment in a generating facility located in Panama, which were largely offset by a $4 million impairment charge associated with the sale of our 50% interest in this facility.

Our West Coast Power investment was the primary driver of equity earnings in this segment during 2004. Total earnings from the investment of $165 million in 2004 were partially offset by an impairment charge of $85 million triggered by the expiration of West Coast Power’s CDWR contract, resulting in net earnings of $80 million. Earnings for 2004 also include a gain of $15 million on the sale of our 50% interest in the Oyster Creek facility in Texas. In addition to the gain on sale, we reported $5 million of earnings from the Oyster Creek investment. In September 2004, we sold our 50% interest in the Hartwell facility, resulting in a gain of approximately $2 million. Our 2004 earnings from Hartwell, including this gain, were $4 million. Our 2004 earnings also included approximately $2 million from Commonwealth, which we sold in the fourth quarter 2004. Finally, our 2004 earnings included $5 million from our investment in Black Mountain (Nevada Cogeneration).

Other Items, Net

Other items, net totaled $26 million of income in 2005, compared to $9 million in 2004. The increase is primarily associated with higher interest income in 2005 due to higher cash balances and higher interest rates.

Interest Expense

Interest expense totaled $389 million in 2005, compared to $453 million in 2004. The decrease is primarily attributable to lower average principal balances in 2005, resulting from the sale of Illinois Power in September 2004, partially offset by the acquisition of Sithe in early 2005, increases in LIBOR and decreased amortization of debt issuance costs in 2005.

Income Tax Benefit

We reported an income tax benefit from continuing operations of $394 million in 2005, compared to an income tax benefit from continuing operations of $172 million in 2004. The 2005 effective tax rate was 33%, compared to 49% in 2004. The 2005 tax benefit includes an $18 million expense and $13 million expense related to an increase in the valuation allowance associated with capital losses and foreign NOLs, respectively. The 2004 tax benefit includes a $27 million benefit related to a reduction in a deferred tax capital losses valuation allowance associated with anticipated gains on asset sales and a $9 million benefit primarily related to IRS, state and foreign audits and settlements and other items. Excluding these items from the 2005 and 2004 calculations would result in effective tax rates of 36% in 2005 and 39% in 2004. In general, differences between these adjusted effective rates and the statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and permanent differences attributable to book-tax basis differences.

Please read Note 14—Income Taxes beginning on page F-42 for further discussion of our income taxes.

Discontinued Operations

Income From Discontinued Operations Before Taxes. Discontinued operations include Calcasieu in our GEN-SO segment, our global liquids business and DMSLP in our former NGL segment, our U.K. CRM business and U.K. natural gas storage assets in our CRM segment and our communications business in Other and Eliminations. The following summarizes the activity included in income from discontinued operations:

Year Ended December 31, 2005


	Calcasieu			U.K. CRM		NGL			Total
	(in millions)
Operating income (loss) included in income from discontinued operations	$	(3	)	$	—	$	1,320		$	1,317
Earnings from unconsolidated investments included in income from discontinued operations		—			—		5			5
Other items, net included in income from discontinued operations		—			6		(22	)		(16	)
Interest expense included in income from discontinued operations										(53	)

Income from discontinued operations before taxes										1,253
Income tax expense										(356	)

Income from discontinued operations									$	897

Year Ended December 31, 2004


	U.K. CRM		DGC		NGL			Total
	(in millions)
Operating income included in income from discontinued operations	$	1	$	—	$	293		$	294
Earnings from unconsolidated investments included in income from discontinued operations		—		—		10			10
Other items, net included in income from discontinued operations		18		3		(22	)		(1	)
Interest expense included in income from discontinued operations									(27	)

Income from discontinued operations before taxes									276
Income tax expense									(111	)

Income from discontinued operations								$	165

As further discussed in Note 4—Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Natural Gas Liquids beginning on page F-23, on October 31, 2005, we completed the sale of DMSLP. As a result of the sale, and as required by SFAS No. 144, we have reclassified the operations related to DMSLP, which comprised of the remaining operations of our NGL segment, from continuing operations to discontinued operations.

In 2005, pre-tax income from discontinued operations of $1,253 million ($897 million after-tax) included $1,250 million in pre-tax income attributable to NGL. In 2004, pre-tax income from discontinued operations of $276 million ($165 million after-tax) included $254 million in pre-tax income attributable to NGL. Included in NGL’s 2005 pre-tax income was a pre-tax gain on the sale of DMSLP of $1,087 million and income attributable to ten months of operations. NGL’s pre-tax income in 2004 included income attributable to twelve months of operations, as well as pre-tax gains of $17 million, $16 million and $36 million, respectively, from our Hackberry LNG, Sherman processing plant and Indian Basin sales, offset by an impairment of $5 million for our Puckett natural gas treating plant and gathering system due to rapidly depleting reserves associated with that facility.

In accordance with EITF Issue 87-24, we have allocated interest expense to discontinued operations associated with debt instruments that were required to be paid upon the sale of DMSLP. Interest expense included in income from discontinued operations, which includes interest incurred on our term loan scheduled to mature in 2010 and our Generation facility debt scheduled to mature in 2007, totaled $53 million and $27 million for 2005 and 2004, respectively.

Income Tax Expense From Discontinued Operations. We recorded an income tax expense from discontinued operations of $356 million in 2005, compared to an income tax expense from discontinued operations of $111 million in 2004. These amounts reflect effective rates of 28% and 40%, respectively. The income tax expense in 2005 includes a $121 million benefit associated with reducing a valuation allowance related to our capital loss carryforward, which primarily relates to our third quarter 2002 sale of NNG. We reduced the valuation allowance as a result of capital gains recognized from our sale of DMSLP. For further information regarding the sale, please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Natural Gas Liquids beginning on page F-23. The income tax expense in 2004 includes $20 million in tax expenses related to the conclusion of prior year tax audits. Excluding these items, the 2005 and 2004 effective tax rates would be 38% and 33%, respectively. In general, differences between these effective rates and the statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and permanent differences attributable to book-tax differences.

Cumulative Effect of Change in Accounting Principle

On December 31, 2005, we adopted FIN No. 47. In connection with its adoption, we realized a cumulative effect loss of approximately $5 million ($7 million pre-tax). For further information, please see Note 2—Summary of Significant Accounting Policies—Asset Retirement Obligations beginning on page F-11.

2007 Outlook

Our current portfolio consists primarily of baseload coal assets in GEN-MW and GEN-NE and natural gas-fired peaking assets throughout GEN-MW and GEN-SO. In addition to the volumes committed under the contracts resulting from the Illinois resource procurement auction and power and steam delivery commitments from our Independence and ERCOT facilities, the output from our facilities is available for other forward sales opportunities to capture attractive market prices. To the extent that we choose not to enter into forward sales, the gross margin from our assets is a function of price movements in the coal, natural gas, fuel oil and power commodity markets. The only intermediate (combined cycle) assets in our current portfolio are the Independence and ERCOT natural gas-fired facilities.

In September 2006, we and the LS Entities announced an agreement to, among other things, combine a portion of the LS Entities’ operating generation portfolio with our current operating assets into a diversified operating portfolio. The combination, which requires receipt of the required vote of our shareholders and the satisfaction of other conditions, will yield a more robust and diverse portfolio than either entity possesses currently. The LS Entities’ portfolio consists primarily of natural gas-fired intermediate (combined cycle) assets with a significant portion of the output committed under multi-year power purchase agreements or hedged through financial agreements. The LS Entities’ portfolio includes significant generating capacity located in the Western Electricity Coordinating Council NERC region, a region that is expected to continue to experience demand growth but in which we currently own no significant generating assets. The combination will result in a more balanced portfolio geographically and in terms of fuel type and dispatch characteristics.

The following summarizes our outlook for our current power generation business and our customer risk management business.

Power Generation Business. Generally, we expect that future financial results will continue to reflect sensitivity to fuel and emissions commodity prices, market structure and prices for electric energy, ancillary services and capacity, transportation and transmission logistics, weather conditions and in-market asset availability (IMA). Our commercial team actively manages commodity price risk associated with our unsold power production by entering into forward sales in the prompt one to three months. Decisions regarding longer term forward sales opportunities to capture attractive market prices are made by the executive management team. To the extent we do not choose to forward sell energy from our generation fleet, changes in commodity prices will affect our earnings based on the direction and significance of the commodity price movement.

GEN- MW. We expect our results to continue to be impacted by power prices, fuel prices, fuel availability and unit availability.

In 2007, GEN-MW results will be affected by the delivery obligations resulting from our participation in the Illinois resource procurement auction. We participated in the Illinois resource procurement auction in September 2006 and were awarded contracts for delivery of up to 1,200 MW into the Ameren portion of the auction for the time period from January 1, 2007 through May 31, 2008 and up to an additional 200 MW for the time period from January 1, 2007 through May 31, 2009. The volumes we expect to deliver under the resulting agreements are significantly less than the maximum volumes AmerenIP was allowed to take under the AmerenIP contract that expired at the end to 2006 (1,400 MW max compared to 2,800 MW max). Under the auction contracts, the Ameren Illinois Utilities will continue to have similar volumetric options as AmerenIP had under the contract which expired at the end of 2006. The power commodity price under the auction-related agreements is higher than existed under our previous contract (approximately $65/MWh under the auction contract compared to $30/MWh under the previous contract) as are Dynegy’s costs to manage deliveries. All other volumes which we produce are available to be sold in the term or spot markets at prevailing market pricing. We anticipate that the revenues generated by our Midwest facilities will improve significantly beginning in 2007 with the implementation of contracts resulting from the auction and the sale of additional volumes into the MISO wholesale markets at prevailing market prices.

Another factor impacting our results in the Midwest in 2007 will be the regulatory environment in Illinois. Within the Illinois political arena, there continues to be challenges to the auction process. There is a possibility of political, legislative, judicial and/or regulatory actions over the next several months that could alter the auction results substantially. Please read Note 18—Regulatory Issues—Illinois Resource Procurement Auction on page F-53 for further details.

Our IMA will also impact GEN-MW’s results. We use IMA to monitor fleet performance over time. This measure quantifies the percentage of generation for each unit that was available when market prices were favorable for participation. IMA is calculated on a unit specific basis as a ratio of dispatchable capacity actually available during periods when each unit is scheduled to be available and the megawatt hours resulting from the capacity of each facility multiplied by the hours when the market pricing for electricity and fuel and the variable costs to operate indicate each unit can be profitably dispatched. Through our focus on safe and efficient operations, we seek to maximize our IMA and, as a result, our revenue generating opportunities. The IMA for our coal-fired fleet through December 31, 2006 was approximately 88%, compared to 90.4% for the comparable period of 2005. We attempt to schedule maintenance and repair work to minimize downtime during peak demand periods, but only to the extent doing so does not compromise a safe working environment for our employees and contractors.

In 2005, DMG entered into a comprehensive, Midwest system-wide settlement with the EPA and other parties, resolving the environmental litigation related to our Baldwin Energy Complex in Illinois. The settlement involves substantial emission reductions from our Illinois coal-fired power plants and the completion of several supplemental environmental projects in the Midwest. Through December 31, 2006, DMG had achieved all of the emission reductions scheduled to date and was developing plans to install additional emission control equipment to meet future, more stringent emission limits. DMG recently received a construction permit for a mercury control project at the Vermilion Power Station that is scheduled for operation by June 30, 2007. Our estimated costs associated with the consent decree projects, which we expect to incur through 2012, are approximately $675 million.

We have diligently worked with our rail service provider to decrease our risk of coal delivery-related disruptions, including the periodic re-deployment of existing rail assets and coal supplies in an opportunistic fashion to provide coal deliveries to our highest margin plants and allow full economic dispatch during peak demand. At this time, we believe that the core issues which created previous delivery uncertainty are resolved and our ability to maintain or build coal inventory at each of our coal-fired facilities continues to be sufficient to meet forecast requirements.

Through 2010, 97% of our Midwest coal requirements are contracted. Additionally, 98% of our coal requirements for 2007 and 2008 are contracted at a fixed price. Our longer term results are sensitive to changes in coal prices to the extent that our current fixed price arrangements expire or are adjusted through contract re-openers or related provisions.

In 2007, we are considering selling our 576 MW Bluegrass generation facility. Please read “Asset Sale Proceeds” beginning on page 48 of our 2006 Form 10-K for further discussion.

GEN-NE. We expect our results to continue to be impacted by power prices, fuel prices, fuel availability and unit availability. Spreads between power and fuel costs are expected to remain volatile as fuel prices change based on demand and weather. This volatility has significant impact on the run-time for the Roseton unit. All of our coal supply requirements for 2007 are contracted at a fixed price. We continue to maintain sufficient coal and oil inventories and contractual commitments to provide us with a stable fuel supply.

Additionally, our results could be affected by potential changes in New York state environmental regulations, as well as our ability to obtain permits necessary for the operation of our facilities. For further discussion of these matters, please see Note 17—Commitments and Contingencies—Danskammer State Pollutant Discharge Elimination System Permit beginning on page F-48 and Note 17—Commitments and Contingencies—Roseton State Pollutant Discharge Elimination System Permit beginning on page F-49, respectively.

GEN-SO. Our results at the CoGen Lyondell facility will be affected by our contract with Lyondell Chemical Company (“Lyondell”) which became effective on January 1, 2007. Under this contract, we sell up to approximately 80 MW of energy and 1.5 million pounds per hour of steam from our CoGen Lyondell cogeneration facility to Lyondell for an initial term from January 2007 through December 2021 and subsequent automatic rollover terms of two years each thereafter through December 2046. Incremental annual operating income associated with this contract is expected to range between $40 million to $55 million. The primary drivers of this improvement are the adjustment to the price of steam supplied to Lyondell and our ability to optimize power and steam generation for the combined Lyondell and CoGen Lyondell facility to capture maximum market potential from the CoGen Lyondell cogeneration facility.

Our peaking facilities in the South continue to contribute revenue from sales of capacity mainly to local load-serving entities or wholesale buyers. We currently have the majority of the portfolio capacity committed in the near-term, and a portion of our portfolio capacity committed on an annual basis through 2015. We continue to pursue opportunities to sell additional capacity from these facilities as well as our Lyondell cogeneration facility. We expect opportunities for capacity sales will develop at times during the year. However, due to the regulated, non-liquid market in the southeast region, our results will continue to be impacted by our ability to complete additional sales to a limited pool of buyers for these products and as a result, we anticipate capacity pricing in the South region will lag the remainder of the country.

In 2007, we are considering selling our 614 MW CoGen Lyondell and our 539 MW Heard County generation facility. Please read “Asset Sale Proceeds” beginning on page 48 of our 2006 Form 10-K for further discussion.

CRM. Our CRM business’ future results of operations will be impacted by our ability to complete our exit from this business. Our CRM business remains a party to certain legacy natural gas, power and emission transactions, most of which have been hedged. Although we continue to work diligently to minimize the financial impact of the CRM segment, we expect to continue to incur cash outflows associated with these legacy transactions. We are proactively working with our customers to exit the remainder of our obligations on economically favorable terms.

CASH FLOW DISCLOSURES

The following table includes data from the operating section of the consolidated statements of cash flows and includes cash flows from our discontinued operations, which are disclosed on a net basis in income from discontinued operations, net of tax expense, in the consolidated statements of operations:


	Years Ended December 31,
	2006			2005			2004
	(in millions)
Operating cash flows from our generation businesses	$	698		$	472		$	421
Operating cash flows from our customer risk management business		(461	)		(21	)		(371	)
Operating cash flows from our natural gas liquids business		—			288			278
Operating cash flows from Illinois Power		—			—			213
Other operating cash flows		(431	)		(769	)		(536	)

Net cash provided by (used in) operating activities	$	(194	)	$	(30	)	$	5

Operating Cash Flow. Our cash flow used in operations totaled $194 million for the twelve months ended December 31, 2006. During the period, our power generation business provided positive cash flow from operations of $698 million primarily due to positive earnings for the period, increases in working capital due to returns of cash collateral postings and decreased accounts receivable balances. Our CRM business used approximately $461 million in cash primarily due to (i) a $370 million termination payment on our Sterlington tolling contract, (ii) a $44 million settlement payment to resolve claims relating to a former Master Netting Setoff Security Agreement with Enron, and (iii) a $37 million settlement of class action claims by California parties alleging price manipulation and false reporting of natural gas trades by our former gas trading business. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Sterlington Contract Termination on page F-21 for further information. Other and Eliminations

includes a use of approximately $431 million in cash primarily due to interest payments to service debt and general and administrative expenses, partially offset by interest income on cash balances and the receipt of approximately $20 million associated with the resolution of a legal dispute.

Our cash flow used in operations totaled $30 million for the twelve months ended December 31, 2005. During the period, our power generation business provided positive cash flow from operations of $472 million, due primarily to positive earnings for the period as well as the return of cash collateral of approximately $66 million during 2005. This was offset by increased accounts receivable balances due to higher prices at December 31, 2005 as compared to December 31, 2004. Our customer risk management business had cash outflows of approximately $21 million, due primarily to fixed payments associated with the former Sterlington and Gregory power tolling arrangement and our final payment of $26 million related to our exit from four long-term natural gas transportation contracts. This was offset partially by the return of approximately $43 million of cash collateral during 2005. Our discontinued natural gas liquids business provided cash flow from operations of $288 million due primarily to positive earnings for the period as well as the return of cash collateral. Other and Eliminations included a use of approximately $769 million in cash due primarily to our payments of $255 million in connection with the settlement of the shareholder class action litigation, interest payments to service debt, pension plan contributions of approximately $31 million, state tax payments and general and administrative expenses.

Our cash flow provided by operations totaled $5 million for the twelve months ended December 31, 2004. During the period, our power generation business provided positive cash flow from operations of $421 million due primarily to positive earnings for the period and increased business activity, partially offset by increased cash collateral posted in lieu of letters of credit. Our customer risk management business used approximately $371 million in cash due primarily to fixed payments associated with the aforementioned power tolling arrangements and related natural gas transportation agreements, a $117.5 million payment related to the restructuring of the Kendall toll, increased cash collateral posted in lieu of letters of credit and our exit from four long-term natural gas transportation contracts. Our discontinued natural gas liquids business provided cash flow from operations of $278 million due primarily to positive earnings, partially offset by increased prepayments due to higher sales. Illinois Power provided cash flow from operations of $213 million due primarily to positive earnings for the period. Other and Eliminations includes a use of approximately $536 million in cash due primarily to interest payments to service debt, settlement payments and general and administrative expenses.

Capital Expenditures and Investing Activities. Cash provided by investing activities during the twelve months ended December 31, 2006 totaled $358 million. Capital spending of $155 million was primarily comprised of $101 million, $22 million, and $24 million in the GEN-MW, GEN-NE, and GEN-SO segments, respectively. The capital spending for each segment primarily related to maintenance and environmental capital projects. In addition, there was approximately $8 million of capital expenditures in the Other segment.

Proceeds from the sale and acquisition of unconsolidated investments, net of cash acquired, totaled $165 million in 2006. This included net cash proceeds of $205 million from the sale of our 50% ownership interest in West Coast Power to NRG. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—West Coast Power for further information. This was partially offset by a payment of $45 million for our acquisition of NRG’s 50% ownership interest in Rocky Road, which included $5 million of cash on hand. Please read Note 3—Business Combinations and Acquisitions—Rocky Road for more information.

Proceeds from assets sales, net totaled $227 million in 2006 and primarily consisted of proceeds from the sale of our Rockingham facility for $194 million. Please read Note 4— Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Rockingham for more information. In addition, we received proceeds of $15 million associated with the sale of our natural gas liquids business in 2005. Please read Note 4— Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Natural Gas Liquids for more information. We also received proceeds of $14 million associated with the sale of a natural gas turbine that was not in use.

The decrease in restricted cash of $121 million related primarily to the return of our $335 million deposit associated with our former cash collateralized facility, offset by a $200 million deposit associated with our new cash collateralized facility and a $14 million increase in the Independence restricted cash balance.

Cash provided by investing activities during the twelve months ended December 31, 2005 totaled $1,824 million. Capital spending of $195 million was primarily comprised of $113 million, $21 million, $9 million and $45 million in the GEN-MW, GEN-NE, GEN-SO and NGL segments, respectively. The capital spending for our GEN-MW segment primarily related to capital maintenance projects, as well as $17 million and $10 million in development capital associated with the completion of the Vermilion and Havana PRB conversions, respectively. Capital spending for our GEN-NE and GEN-SO segments primarily related to maintenance and environmental projects. Capital spending in our NGL segment primarily related to capital maintenance projects and wellconnects.

The cost to acquire Sithe Energies, net of cash proceeds, totaled $120 million. The increase in restricted cash of $353 million related primarily to a $335 million deposit associated with our cash collateralized facility, as well as an $18 million increase in the Independence restricted cash balance.

Net cash proceeds from asset sales of $2,488 million consisted of the following items:

•

$2,382 million, net of transaction costs, from the sale of DMSLP;

•

a $100 million return of funds held in escrow, offset by a $5 million payment to Ameren associated with a working capital adjustment, both of which related to the sale of Illinois Power; and

•

$10 million from the sale of land at our Port Everglades facility.

Net cash provided by investing activities during 2004 totaled $262 million. Capital spending of $311 million was comprised primarily of $113 million, $17 million, $15 million, $61 million and $92 million in the GEN-MW, GEN-NE, GEN-SO, NGL and REG segments, respectively. The capital spending for our GEN-MW segment primarily related to capital maintenance projects, as well as approximately $41 million related to developmental projects. Capital spending for our GEN-NE and GEN-SO primarily related to maintenance and environmental projects. Capital spending in our NGL segment related primarily to maintenance capital projects and wellconnects, as well as approximately $21 million on developmental projects. Capital spending in our REG segment related primarily to projects intended to maintain system reliability and new business services.

Net cash proceeds from asset sales of $576 million consisted of the following items:

•

$217 million from the sale of Illinois Power, net of cash retained by Illinois Power of $52 million;

•

$152 million from the sale of our equity investments in the Oyster Creek, Hartwell, Michigan Power, Jamaica and Commonwealth generating facilities;

•

$99 million from the sale of Joppa;

•

$48 million from the sale of Indian Basin;

•

$34 million from the sale of Sherman;

•

$17 million from the sale of our remaining financial interest in the Hackberry LNG project; and

•

$9 million from the sale of PESA.

The cash proceeds were partially offset by $3 million of capitalized business acquisition costs incurred in connection with the Sithe Energies acquisition.

Financing Activities. Cash used in financing activities during the twelve months ended December 31, 2006 totaled $1,342 million. Repayments of long-term debt totaled $1,930 million for the twelve months ended December 31, 2006 and consisted of the following payments:

•

$900 million in aggregate principal amount on our 10.125% Second Priority Senior Secured Notes due 2013;

•

$614 million in aggregate principal amount on our 9.875% Second Priority Senior Secured Notes due 2010;

•

$225 million in aggregate principal amount on our Second Priority Senior Secured Floating Rate Notes due 2008;

•

$150 million in aggregate principal amount on our Term Loan;

•

$23 million in aggregate principal amount on our 7.45% Senior Notes due 2006; and

•

$18 million in aggregate principal amount on our 8.50% secured bonds due 2007.

Debt conversion costs of $249 million consisted of the following payments:

•

$204 million to redeem the Second Priority Senior Secured Notes mentioned above, including approximately $3 million of transaction costs;

•

$44 million aggregate premium to induce conversion of our $225 million 4.75% Convertible Subordinated Debentures due 2023; and

•

$1 million in transaction costs associated with the redemption of our Series C Preferred.

The repayments were partially offset by $1,071 million of proceeds from the following sources, net of approximately $29 million of debt issuance costs:

•

$750 million aggregate principal amount from a private offering of our 8.375% Senior Unsecured Notes due 2016;

•

$200 million, letter of credit facility due 2012; and

•

$150 million, term loan due 2012.

Proceeds from the issuance of common stock consisted primarily of approximately $178 million in proceeds from a public offering of 40.25 million shares of our Class A common stock at $4.60 per share, net of underwriting fees. Dividend payments totaling $17 million were also made on our Series C Preferred prior to its redemption.

Cash used in financing activities during the twelve months ended December 31, 2005 totaled $873 million. Repayments of long-term debt totaled $1,432 million for the twelve months ended December 31, 2005 and consisted of the following payments:

•

$600 million aggregate principal amount outstanding under a revolver due May 2007;

•

$597 million on the term loan;

•

$183 million on the Riverside facility debt;

•

$34 million on the Independence Senior Notes due 2007; and

•

$18 million on a maturing series of DHI senior notes.

The repayments were partially offset by proceeds from the October 2005 draw-down on the $600 million aggregate principal outstanding revolver due May 2007. Cash used in financing activities also includes semi-annual dividend payments totaling $22 million on our Series C Preferred and distributions of $25 million to minority interest owners.

Net cash used in financing activities during 2004 totaled $115 million. Our financing cash outflows were primarily related to repayments of long-term debt totaling $650 million and consisted primarily of the following payments:

•

$223 million to redeem the outstanding Chevron junior notes;

•

$185 million under our ABG Gas Supply financing;

•

$95 million for a maturing series of Illinova senior notes;

•

$78 million on the Tilton capital lease; and

•

$65 million on Illinois Power’s transitional funding trust notes.

These repayments of long-term debt were offset by proceeds from our $600 million aggregate principal outstanding secured term loan, net of issuance costs of $19 million. We made semi-annual dividend payments totaling $22 million on our Series C Preferred and made distributions to minority interest owners totaling $32 million.

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.

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 six critical accounting policies that require a significant amount of estimation and judgment and are considered to be important to the portrayal of our financial position and results of operations:

•

Revenue Recognition and Valuation of Risk Management Assets and Liabilities;

•

Valuation of Tangible and Intangible Assets;

•

Estimated Useful Lives;

•

Accounting for Contingencies, Guarantees and Indemnifications;

•

Accounting for Income Taxes; and

•

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

Revenue Recognition and Valuation of Risk Management Assets and Liabilities

We utilize two comprehensive accounting models in reporting our consolidated financial position and results of operations as required by GAAP—an accrual model and a fair value model. We determine the appropriate model for our operations based on guidance provided in applicable accounting standards and positions adopted by the FASB or the SEC.

The accrual model is used to account for substantially all of the operations conducted in our GEN-MW, GEN-NE and GEN-SO segments. These segments consist largely of the ownership and operation of physical assets that we use in various generation operations. We earn revenue from our facilities in three primary ways: (1) sale of energy generated by our facilities; (2) 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; and (3) sale of capacity. We recognize revenue from these transactions and transactions from our legacy businesses when the product or service is delivered to a customer.

The fair value model is used to account for forward physical and financial transactions, which meet the definition of a derivative contract as defined by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended, (SFAS No. 133). The criteria are complex, but generally require these contracts to relate to future periods, to contain fixed price and volume components and to have terms that require or permit net settlement of the contract in cash or the equivalent. SFAS No. 133 concluded that these contracts should be accounted for at fair value. In part, this conclusion is based on the cash settlement provisions in these agreements, as well as the volatility in commodity prices, interest rates and, if applicable, foreign exchange rates, which impact the valuation of these contracts. Since these transactions may be settled in cash or the equivalent, the value of the assets and liabilities associated with these transactions is reported at estimated settlement value based on current forward prices and rates as of each balance sheet date.

Typically, derivative contracts can be accounted for in three different ways: (1) as an accrual contract, if the criteria for the “normal purchase normal sale” exception are met and documented; (2) as a cash flow or fair value hedge, if the criteria are met and documented; or (3) as a mark-to-market contract with changes in fair value recognized in current period earnings. Generally, we only mark-to-market through earnings our derivative contracts if they do not qualify for the “normal purchase normal sale” exception or as a cash flow hedge. 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.

In order to estimate the fair value of our portfolio of transactions, which meet the definition of a derivative and do not qualify for the “normal purchase normal sale” exception, we use a liquidation value approach assuming that the ability to transact business in the market remains at historical levels. The estimated fair value of the portfolio is computed by multiplying all existing positions in the portfolio by estimated prices, reduced by a time value of money adjustment and reserves for credit and price. The estimated prices in this valuation are based either on (1) prices obtained from market quotes, when there are an adequate number of quotes to consider the period liquid, or, if market quotes are unavailable or the market is not considered liquid, (2) prices from a proprietary model which incorporates forward energy prices derived from market quotes and values from previously executed transactions. The amounts recorded as revenue change as these estimates are revised to reflect actual results and changes in market conditions or other factors, many of which are beyond our control. In addition, due to assumptions inherent to the modeling process, the fair value determined by another party could differ significantly from the amounts included in our financial statements.

Please read Note 6—Risk Management Activities and Financial Instruments beginning on page F-26 for further discussion of our accounting for risk management instruments.

Valuation of Tangible and Intangible Assets

We evaluate long-lived assets, such as property, plant and equipment and investments, 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:

•

significant underperformance relative to historical or projected future operating results;

•

significant changes in the manner of our use of the assets or the strategy for our overall business;

•

significant negative industry or economic trends; and

•

significant declines in stock value for a sustained period.

We assess the carrying value of our property, plant and equipment in accordance with SFAS No. 144. If an impairment is indicated, the amount of the impairment loss recognized would be determined by the amount the book value exceeds the estimated fair value of the assets. The estimated fair value may include estimates based upon discounted cash-flow projections, recent comparable market transactions or quoted prices to determine if an impairment loss is required. For assets identified as held for sale, the book value is compared to the estimated sales price less costs to sell. There is a significant amount of judgment involved in cash-flow estimates, including assumptions regarding market convergence, discount rates and capacity. The assumptions used by another party could differ significantly from our assumptions. Please read Note 5—Restructuring and Impairment Charges beginning on page F-24 for discussion of impairment charges we recognized in 2006, 2005 and 2004.

We follow the guidance of APB 18, “The Equity Method of Accounting for Investments in Common Stock”, SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities”, (SFAS No. 115), and EITF Issue 02-14, “Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock”, (EITF 02-14), when reviewing our investments. The book value of the investment is compared to the estimated fair value, based either on discounted cash flow projections or quoted market prices, if available, to determine if an impairment is required. We record a loss when the decline in value is considered other than temporary.

Our assessments regarding valuation of tangible and intangible assets are subject to estimates and judgment of management. Market conditions, energy prices, estimated useful lives of the assets, discount rate assumptions and legal factors impacting our business may have a significant effect on the estimates and judgment of management. If different judgments were applied, estimates could differ significantly. Actual results could vary materially from these estimates.

Please read Note 11—Intangible Assets beginning on page F-35 for further discussion of our accounting for intangible assets.

Estimated Useful Lives

The estimated useful lives of our long-lived assets are used to compute depreciation expense, 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. Without these continued capital expenditures, the useful lives of these assets could decrease significantly. 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.

Please read Note 9—Property, Plant and Equipment beginning on page F-31 for further discussion of our estimated useful lives.

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. In accordance with SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5), we record a loss contingency 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 contingencies on an ongoing basis to ensure that we have appropriate reserves recorded on our consolidated balance sheets as required by SFAS No. 5. 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 judgment 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.

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 follow the guidance of FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN No. 45), for disclosure and accounting of various guarantees and indemnifications entered into during the course of business. When a guarantee or indemnification subject to FIN No. 45 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, however 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.

Under the provisions of SFAS No. 143, “Asset Retirement Obligations” (SFAS No. 143), and FIN No. 47 “Accounting for Conditional Asset Retirements” (FIN No. 47), we are required to record the present value of the future obligations to retire tangible, long-lived assets on our consolidated balance sheets as liabilities when the liability is incurred. Significant judgment is involved in estimating our future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates for the amount or timing of the cash flows change, the change may have a material impact on our results of operations.

Please read Note 2—Summary of Significant Accounting Policies—Asset Retirement Obligations beginning on page F-11 for further discussion of our accounting for AROs.

Accounting for Income Taxes

We follow the guidance in SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109), which requires that we use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.

As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing tax and accounting treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheets.

We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we must establish a valuation allowance. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.

Management believes future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize deferred tax assets for which no reserve has been established. While we have considered these factors in assessing the need for a valuation allowance, there is no assurance that a valuation allowance would not need to be established in the future if information about future years changes. Any change in the valuation allowance would impact our income tax benefit (expense) and net income (loss) in the period in which such a determination is made.

Please read Note 14—Income Taxes beginning on page F-42 for further discussion of our accounting for income taxes and any change in our valuation allowance.

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

Our pension and other post-retirement benefit costs are developed from actuarial valuations. Inherent in these valuations are key assumptions including the discount rate and expected long-term rate of return on plan assets. Material changes in our pension and other post-retirement benefit costs may occur in the future due to changes in these assumptions, changes in the number of plan participants and changes in the level of benefits provided.

The discount rate is subject to change each year, consistent with changes in applicable high-quality, long-term corporate bond indices. Long-term interest rates increased during 2006. Accordingly, at December 31, 2006, we used a discount rate of 5.87% for pension plans and 5.90% for other retirement plans, an increase of 35 and 37 basis points, respectively, from the 5.52% for pension plans rate and 5.53% for other retirement plans rate used as of December 31, 2005. This increase in the discount rate decreased the underfunded status of the plans by $13 million.

Effective December 31, 2005, we changed to a yield curve approach for determining the discount rate. Projected benefit payments were matched against the discount rates in the Citigroup Pension Discount Curve to produce a weighted-average equivalent discount rate of 5.52% for the pension plans and 5.53% for the other post-retirement plans. In prior years, the discount rate we used was based on Moody’s Aa Corporate Bond Rate. We changed our methodology because we believe the yield curve approach is a more accurate estimate of plan liabilities particularly due to the significant change in the composition of the participants in our pension and other retirement plans as a result of the sales of DMSLP and Illinois Power.

The expected long-term rate of return on pension plan assets is selected by taking into account the asset mix of the plans and the expected returns for each asset category. Based on these factors, our expected long-term rate of return as of January 1, 2007 and 2006 was 8.25%.

We adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132 (R)” (SFAS No. 158), on December 31, 2006. On December 31, 2006, our annual measurement date, the accumulated benefit obligation related to our pension plans exceeded the fair value of the pension plan assets (such excess is referred to as an unfunded accumulated benefit obligation). Under the provisions of SFAS No. 158, we recorded an adjustment to accumulated other comprehensive income of approximately $56 million upon adoption.

A relatively small difference between actual results and assumptions used by management may have a material effect on our financial statements. Assumptions used by another party could be different than our assumptions. The following table summarizes the sensitivity of pension expense and our projected benefit obligation, or PBO, to changes in the discount rate and the expected long-term rate of return on pension assets:


	Impact on PBO, December 31, 2006			Impact on 2007 Expense
	(in millions)
Increase in Discount Rate—50 basis points	$	(16	)	$	(2	)
Decrease in Discount Rate—50 basis points		18			2
Increase in Expected Long-term Rate of Return—50 basis points		—			(1	)
Decrease in Expected Long-term Rate of Return—50 basis points		—			1

We expect to make $25 million in cash contributions related to our pension plans during 2007. In addition, it is likely that we will be required to continue to make contributions to the pension plans beyond 2007. Although it is difficult to estimate these potential future cash requirements due to uncertain market conditions, we currently expect that the cash requirements would be approximately $29 million in 2008 and $10 million in 2009.

Please read Note 20—Employee Compensation, Savings and Pension Plans beginning on page F-61 for further discussion of our pension-related assets and liabilities.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 2—Summary of Significant Accounting Policies—Accounting Principles Adopted beginning on page F-16 for a discussion of recently issued accounting pronouncements affecting us. Specifically, we adopted SFAS No. 123(R), and SFAS No. 154, “Accounting Changes and Error Corrections—A Replacement of APB Opinion No. 20 and SFAS No. 3”, on

January 1, 2006 and SFAS No. 158 on December 31, 2006. We adopted EITF Issue 05-6, “Determining the Amortization Period for Leasehold Improvements“, and FSP FIN No. 45-3, “Application of FASB Interpretation No. 45 to Minimum Revenue Guarantees Granted to a Business or Its Owners”, on January 1, 2006. We adopted FIN No. 47 on December 31, 2005. We adopted EITF Issue 04-8, EITF Issue 02-14 and certain provisions of FIN No. 46R on January 1, 2004.

RISK-MANAGEMENT DISCLOSURES

The following table provides a reconciliation of the risk-management data on the consolidated balance sheets:


	As of and for the Year Ended December 31, 2006
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2006	$	(112	)
Risk-management losses recognized through the income statement in the period, net		39
Cash paid related to risk-management contracts settled in the period, net		(22	)
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other (2)		148

Fair value of portfolio at December 31, 2006	$	53

(1)	Our modeling methodology has been consistently applied.

(2)	This amount consists of changes in value associated with cash flow hedges on forward power sales and fair value hedges on debt.

The net risk-management asset of $53 million is the aggregate of the following line items on the consolidated balance sheets: Current Assets—Assets from risk-management activities, Other Assets—Assets from risk-management activities, Current Liabilities—Liabilities from risk-management activities and Other Liabilities—Liabilities from risk-management activities.

Risk-Management Asset and Liability Disclosures

The following table depicts the mark-to-market value and cash flow components, based on contract terms, of our net risk-management assets and liabilities at December 31, 2006. As opportunities arise to monetize positions that we believe will result in an economic benefit to us, we may receive or pay cash in periods other than those depicted below.

Net Risk-Management Asset and Liability Disclosures


	Total			2007			2008			2009		2010		2011		Thereafter
	(in millions)
Mark-to-Market (1)(3)	$	(44	)	$	(45	)	$	(3	)	$	—	$	—	$	1	$	3
Cash Flow (2)		(43	)		(45	)		(4	)		—		—		1		5

(1)

Mark-to-market reflects the fair value of our risk-management asset position, which considers time value, credit, price and other reserves necessary to determine fair value. These amounts exclude the fair value associated with certain derivative instruments designated as hedges. The net risk-management asset at December 31, 2006 of $53 million on the consolidated balance sheets includes the $44 million liability herein offset by hedging instruments. Cash flows have been segregated between periods based on the delivery date required in the individual contracts.

(2)

Cash flow reflects undiscounted cash inflows and outflows by contract based on the tenor of individual contract position for the remaining periods. These anticipated undiscounted cash flows have not been adjusted for counterparty credit or other reserves. These amounts exclude the cash flows associated with certain derivative instruments designated as hedges.

(3)	Our mark-to-market values at December 31, 2006 were derived solely from market quotations instead of the combination of long-term valuation models and market quotations used in prior years.

Derivative Contracts

The absolute notional contract amounts associated with our commodity risk-management, interest rate and foreign currency exchange contracts are discussed in Item 7A. Quantitative and Qualitative Disclosures About Market Risk below.

Item 8. Financial Statements and Supplementary Data

Our financial statements and financial statement schedules are set forth at pages F-1 through F-101 inclusive, found at the end of this filing, and are incorporated herein by reference.


		Page
Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2006 and 2005		F-4
Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004		F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004		F-6
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2006, 2005 and 2004		F-7
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2006, 2005 and 2004		F-8
Notes to Consolidated Financial Statements		F-9

Financial Statement Schedules
Schedule I – Parent Company Financial Statements		F-74
Schedule II – Valuation and Qualifying Accounts		F-78
West Coast Power LLC Consolidated Financial Statements*		F-79

*	West Coast Power’s consolidated financial statements are included herein pursuant to Rule 3-09 of Regulation S-X.

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Dynegy Inc:

We have completed integrated audits of Dynegy Inc.’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedules

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Dynegy Inc. and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying index present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 17, the Company is the subject of substantial litigation. The Company’s ongoing liquidity, financial position and operating results may be adversely impacted by the nature, timing and amount of the resolution of such litigation. The consolidated financial statements do not include any adjustments, beyond existing accruals applicable under Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies,” that might result from the ultimate resolution of such matters.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

F-2

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP

Houston, Texas

February 27, 2007, except for Notes 4, 14, 16 and 21,

as to which the date is May 14, 2007

F-3

DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

(in millions, except share data)


	December 31, 2006			December 31, 2005
ASSETS
Current Assets
Cash and cash equivalents	$	371		$	1,549
Restricted cash		280			397
Accounts receivable, net of allowance for doubtful accounts of $48 and $103, respectively		257			611
Accounts receivable, affiliates		1			29
Inventory		194			214
Assets from risk-management activities		794			665
Deferred income taxes		93			14
Prepayments and other current assets		92			227

Total Current Assets		2,082			3,706

Property, Plant and Equipment		6,473			6,515
Accumulated depreciation		(1,522	)		(1,192	)

Property, Plant and Equipment, Net		4,951			5,323
Other Assets
Unconsolidated investments		—			270
Restricted investments		83			85
Assets from risk-management activities		16			165
Intangible assets		347			392
Deferred income taxes		12			3
Other long-term assets		139			182

Total Assets	$	7,630		$	10,126

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	172		$	504
Accounts payable, affiliates		—			46
Accrued interest		66			159
Accrued liabilities and other current liabilities		231			649
Liabilities from risk-management activities		722			687
Notes payable and current portion of long-term debt		68			71

Total Current Liabilities		1,259			2,116

Long-term debt		2,990			4,028
Long-term debt to affiliates		200			200

Long-Term Debt		3,190			4,228
Other Liabilities
Liabilities from risk-management activities		35			255
Deferred income taxes		469			558
Other long-term liabilities		410			429

Total Liabilities		5,363			7,586

Commitments and Contingencies (Note 17)
Redeemable Preferred Securities, redemption value of zero at December 31, 2006 and $400 at December 31, 2005 (Note 15)		—			400
Stockholders’ Equity
Class A Common Stock, no par value, 900,000,000 shares authorized at December 31, 2006 and December 31, 2005; 403,137,339 and 305,129,052 shares issued and outstanding at December 31, 2006 and December 31, 2005, respectively		3,367			2,949
Class B Common Stock, no par value, 360,000,000 shares authorized at December 31, 2006 and December 31, 2005; 96,891,014 shares issued and outstanding at December 31, 2006 and December 31, 2005		1,006			1,006
Additional paid-in capital		39			51
Subscriptions receivable		(8	)		(8	)
Accumulated other comprehensive income, net of tax		67			4
Accumulated deficit		(2,135	)		(1,793	)
Treasury stock, at cost, 1,787,004 and 1,714,026 shares at December 31, 2006 and December 31, 2005, respectively		(69	)		(69	)

Total Stockholders’ Equity		2,267			2,140

Total Liabilities and Stockholders’ Equity	$	7,630		$	10,126

See the notes to the consolidated financial statements

F-4

DYNEGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except share data)


	Year Ended December 31,
	2006			2005			2004
Revenues	$	2,016		$	2,311		$	2,444
Cost of sales, exclusive of depreciation shown separately below		(1,385	)		(2,413	)		(1,846	)
Depreciation and amortization expense		(228	)		(218	)		(232	)
Impairment and other charges		(119	)		(46	)		(78	)
Gain (loss) on sale of assets, net		3			(1	)		(58	)
General and administrative expenses		(196	)		(468	)		(330	)

Operating income (loss)		91			(835	)		(100	)
Earnings (losses) from unconsolidated investments		(1	)		2			192
Interest expense		(382	)		(389	)		(453	)
Debt conversion costs		(249	)		—			—
Other income and expense, net		54			26			12
Minority interest expense		—			—			(3	)

Loss from continuing operations before income taxes		(487	)		(1,196	)		(352	)
Income tax benefit		157			394			172

Loss from continuing operations		(330	)		(802	)		(180	)
Income (loss) from discontinued operations, net of tax benefit (expense) of $5, $(356) and $(111), respectively (Note 4)		(4	)		897			165

Income (loss) before cumulative effect of change in accounting principles		(334	)		95			(15	)
Cumulative effect of change in accounting principles, net of tax benefit of zero, $2 and zero, respectively (Note 2)		1			(5	)		—

Net income (loss)		(333	)		90			(15	)
Less: preferred stock dividends		9			22			22

Net income (loss) applicable to common stockholders	$	(342	)	$	68		$	(37	)

Earnings (Loss) Per Share (Note 16):
Basic earnings (loss) per share:
Loss from continuing operations	$	(0.74	)	$	(2.13	)	$	(0.53	)
Income (loss) from discontinued operations		(0.01	)		2.32			0.43
Cumulative effect of change in accounting principles		—			(0.01	)		—

Basic earnings (loss) per share	$	(0.75	)	$	0.18		$	(0.10	)

Diluted earnings (loss) per share:
Loss from continuing operations	$	(0.74	)	$	(2.13	)	$	(0.53	)
Income (loss) from discontinued operations		(0.01	)		2.32			0.43
Cumulative effect of change in accounting principles		—			(0.01	)		—

Diluted earnings (loss) per share	$	(0.75	)	$	0.18		$	(0.10	)

Basic shares outstanding		459			387			378
Diluted shares outstanding		509			513			504

See the notes to the consolidated financial statements

F-5

DYNEGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	Year Ended December 31,
	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(333	)	$	90		$	(15	)
Adjustments to reconcile income (loss) to net cash flows from operating activities:
Depreciation and amortization		265			278			356
Impairment and other charges		155			46			83
(Earnings) losses from unconsolidated investments, net of cash distributions		1			73			(66	)
Risk-management activities		(87	)		46			(50	)
Gain on sale of assets, net		(5	)		(1,096	)		(11	)
Deferred taxes		(162	)		(73	)		(74	)
Cumulative effect of change in accounting principles (Note 2)		(1	)		5			—
Reserve for doubtful accounts		(35	)		1			—
Liability associated with natural gas transportation contracts (Note 4)		—			—			(148	)
Independence toll settlement charge (Note 3)		—			169			—
Legal and settlement charges		(2	)		119			104
Sterlington toll settlement charge (Note 4)		—			364			—
Sithe Subordinated Debt exchange charge (Note 12)		36			—			—
Debt conversion costs		249			—			—
Other		71			18			(49	)
Changes in working capital:
Accounts receivable		391			(134	)		4
Inventory		8			(91	)		(36	)
Prepayments and other assets		126			148			(107	)
Accounts payable and accrued liabilities		(885	)		(2	)		(13	)
Changes in non-current assets		11			(15	)		(22	)
Changes in non-current liabilities		3			24			49

Net cash provided by (used in) operating activities		(194	)		(30	)		5

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(155	)		(195	)		(311	)
Proceeds from asset sales, net		227			2,488			576
Business acquisitions, net of cash acquired		(8	)		(120	)		(3	)
Proceeds from exchange of unconsolidated investments, net of cash acquired (Note 3 and Note 4)		165			—			—
(Increase) decrease in restricted cash		121			(353	)		—
Other investing, net		8			4			—

Net cash provided by investing activities		358			1,824			262

CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from long-term borrowings		1,071			600			581
Repayments of borrowings		(1,930	)		(1,432	)		(650	)
Debt conversion costs		(249	)		—			—
Redemption of Series C Preferred (Note 13)		(400	)		—			—
Net proceeds from issuance of capital stock		183			2			5
Dividends and other distributions, net		(17	)		(22	)		(22	)
Other financing, net		—			(21	)		(29	)

Net cash used in financing activities		(1,342	)		(873	)		(115	)

Effect of exchange rate changes on cash		—			—			(1	)
Net increase (decrease) in cash and cash equivalents		(1,178	)		921			151
Cash and cash equivalents, beginning of period		1,549			628			477

Cash and cash equivalents, end of period	$	371		$	1,549		$	628

See the notes to the consolidated financial statements

F-6

DYNEGY INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(in millions)


	Common Stock		Additional Paid-In Capital			Subscriptions Receivable			Accumulated Other Comprehensive Income (Loss)			Accumulated Deficit			Treasury Stock			Total
December 31, 2003	$	3,854	$	41		$	(8	)	$	(20	)	$	(1,824	)	$	(68	)	$	1,975
Net loss		—		—			—			—			(15	)		—			(15	)
Other comprehensive income, net of tax		—		—			—			7			—			—			7
Options exercised		5		(6	)		—			—			—			—			(1	)
Dividends and other distributions		—		—			—			—			(22	)		—			(22	)
401(k) plan and profit sharing stock		6		—			—			—			—			—			6
Options and restricted stock granted		—		6			—			—			—			—			6

December 31, 2004	$	3,865	$	41		$	(8	)	$	(13	)	$	(1,861	)	$	(68	)	$	1,956
Net income		—		—			—			—			90			—			90
Other comprehensive income, net of tax		—		—			—			17			—			—			17
Options exercised		4		1			—			—			—			(1	)		4
Dividends and other distributions		—		—			—			—			(22	)		—			(22	)
401(k) plan and profit sharing stock		5		—			—			—			—			—			5
Options and restricted stock granted		—		9			—			—			—			—			9
Shareholder litigation settlement		81		—			—			—			—			—			81

December 31, 2005	$	3,955	$	51		$	(8	)	$	4		$	(1,793	)	$	(69	)	$	2,140
Net loss		—		—			—			—			(333	)		—			(333	)
Other comprehensive income, net of tax		—		—			—			98			—			—			98
Adjustment to initially apply SFAS No. 158, net of tax benefit of $21		—		—			—			(35	)		—			—			(35	)
Options exercised		5		(5	)		—			—			—			—			—
Dividends and other distributions		—		—			—			—			(9	)		—			(9	)
401(k) plan and profit sharing stock		3		—			—			—			—			—			3
Options and restricted stock granted		—		8			—			—			—			—			8
Equity issuance (Note 12)		185		(7	)		—			—			—			—			178
Equity conversion (Note 12)		225		(8	)		—			—			—			—			217

December 31, 2006	$	4,373	$	39		$	(8	)	$	67		$	(2,135	)	$	(69	)	$	2,267

See the notes to the consolidated financial statements

F-7

DYNEGY INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in millions)


	Year Ended December 31,
	2006			2005			2004
Net income (loss)	$	(333	)	$	90		$	(15	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		95			(70	)		(62	)
Reclassification of mark-to-market (gains) losses to earnings, net		(17	)		84			36

Changes in cash flow hedging activities, net (net of tax benefit (expense) of $(46), $(8) and $16, respectively)		78			14			(26	)
Foreign currency translation adjustments		(1	)		8			(11	)
Minimum pension liability (net of tax benefit (expense) of ($5), $3 and $(26), respectively)		10			(5	)		44
Unrealized gains on securities, net of tax expense of $(7)		11			—			—

Other comprehensive income, net of tax		98			17			7

Comprehensive income (loss)	$	(235	)	$	107		$	(8	)

See the notes to the consolidated financial statements

F-8

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Operations of the Company

Dynegy Inc. (together with our subsidiaries, “we”, “us” or “our”) is a holding company and conducts substantially all of its business through its 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: (1) the Midwest segment (GEN-MW); (2) the Northeast segment (GEN-NE); and (3) the South segment (GEN-SO). We also separately report the results of our CRM business, which primarily consists of our Kendall power tolling arrangement (and does not include the Sithe toll which is in GEN-NE and is an intercompany agreement) as well as legacy natural gas, power and emissions trading positions. Because of the diversity among their respective operations, 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 and interest. As described below, our natural gas liquids business, which was conducted through DMSLP and its subsidiaries, was sold to Targa Resources, Inc. (Targa) on October 31, 2005. Additionally, as described below, our former regulated energy delivery business, which was conducted through Illinois Power and its subsidiaries, was sold to Ameren Corporation on September 30, 2004.

Note 2—Summary of Significant Accounting Policies

The preparation of consolidated financial statements in conformity with GAAP requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (i) developing fair value assumptions, including estimates of future cash flows and discount rates, (ii) analyzing tangible and intangible assets for possible impairment, (iii) estimating the useful lives of our assets, (iv) assessing future tax exposure and the realization of deferred tax assets, (v) determining amounts to accrue for contingencies, guarantees and indemnifications and (vi) estimating various factors used to value our pension assets and liabilities. Actual results could differ materially from our estimates.

Principles of Consolidation. The accompanying consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries and VIEs for which we are the primary beneficiary. Intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to prior-period amounts to conform with current-period presentation.

Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid short-term investments with original maturities of three months or less.

Restricted Cash. Restricted cash represents cash that is not readily available for general purpose cash needs. Restricted cash at December 31, 2006 includes cash posted to support the letter of credit component of our Fourth Amended and Restated Credit Facility. We are required to post cash collateral in an amount equal to 103% of outstanding letters of credit.

Restricted cash at December 31, 2006 also includes amounts related to the terms of the indenture governing the Independence senior debt, which among other things, prohibit cash distributions by Independence to its affiliates, including us, unless certain project reserve accounts are funded to specified levels and the required debt service coverage ratio is met. Independence also has restricted investment balances which are included in prepayments and other current assets and restricted investments on our consolidated balance sheets. We include all changes in restricted cash, including those associated with the Independence senior debt, in investing cash flows on the consolidated statements of cash flows.

F-9

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Allowance for Doubtful Accounts. We establish provisions for losses on accounts receivable if it becomes probable we will not collect all or part of outstanding balances. We review collectibility and establish or adjust our allowance as necessary. We primarily use a percent of balance methodology and methodologies involving historical levels of write-offs. The specific identification method is also used in certain circumstances.

Unconsolidated Investments. We use the equity method of accounting for investments in affiliates over which we exercise significant influence, generally occurring in ownership interests of 20% to 50%, and also occurring in lesser ownership percentages due to voting rights or other factors. Our share of net income (loss) from these affiliates is reflected in the consolidated statements of operations as earnings (losses) from unconsolidated investments. Any excess of our investment in affiliates, as compared to our share of the underlying equity that is not recognized as goodwill, is amortized over the estimated economic service lives of the underlying assets. All investments in unconsolidated affiliates are periodically assessed for other-than-temporary declines in value, with write-downs recognized in earnings from unconsolidated investments in the consolidated statements of operations.

Please read Note 5—Restructuring and Impairment Charges beginning on page F-24 for a discussion of impairment charges we recognized in 2006, 2005, and 2004.

Available-for-Sale Securities. For securities classified as available-for-sale that have readily determinable fair values, the change in the unrealized gain or loss, net of deferred income tax, is recorded as a separate component of accumulated other comprehensive income (loss) in the consolidated statements of comprehensive income (loss). Realized gains and losses on investment transactions are determined using the specific identification method.

Inventory. Our natural gas, coal, emissions allowances and fuel oil inventories are carried at the lower of weighted average cost or at market. Our materials and supplies inventory is carried at the lower of cost or market using the specific identification method.

We adopted EITF Issue 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”, in the fourth quarter 2005. Accordingly, we account for exchanges of inventory with the same counterparty as one transaction at fair value.

We may opportunistically sell emissions allowances, subject to certain regulatory limitations and restrictions contained in our DMG consent decree, or hold them in inventory until they are needed. In the past, we have sold emission allowances that relate to future periods. To the extent the proceeds received from the sale of such allowances exceed our cost, we defer the associated gain until the period to which the allowance relates, as we may be required to purchase emissions allowances in future periods. As of December 31, 2006, we had aggregate deferred gains of $20 million, consisting of $11 million included in Other accrued liabilities and $9 million included in Other long-term liabilities, respectively, on our consolidated balance sheets. As of December 31, 2005, we had aggregate deferred gains of $22 million, consisting of $11 million included in Other accrued liabilities and $11 million included in Other long-term liabilities, respectively, on our consolidated balance sheets.

Property, Plant and Equipment. Property, plant and equipment, which consists principally of power generating facilities, is recorded at historical cost. Expenditures for major replacements, renewals and major maintenance are capitalized and depreciated over the expected maintenance cycle. We consider major maintenance to be expenditures incurred on a cyclical basis to maintain and prolong the efficient operation of our assets. Expenditures for repairs and minor renewals to maintain assets in operating condition are expensed. Depreciation is provided using the straight-line method over the estimated economic service lives of the assets,

F-10

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

ranging from 3 to 40 years. Composite depreciation rates (which we refer to as composite rates) are applied to functional groups of assets having similar economic characteristics. The estimated economic service lives of our functional asset groups are as follows:


Asset Group		Range of Years
Power Generation Facilities		20 to 40
Transportation Equipment		5 to 10
Buildings and Improvements		10 to 39
Office and Miscellaneous Equipment		3 to 20

Gains and losses on sales of individual assets or asset groups are reflected in gain (loss) on sale of assets, net, in the consolidated statements of operations. We assess the carrying value of our property, plant and equipment in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144). If an impairment is indicated, the amount of the impairment loss recognized would be determined by the amount the book value exceeds the estimated fair value of the assets. The estimated fair value may include estimates based upon discounted cash-flow projections, recent comparable market transactions or quoted prices to determine if an impairment loss is required. For assets identified as held for sale, the book value is compared to the estimated sales price less costs to sell.

Please read Note 5—Restructuring and Impairment Charges beginning on page F-24 for a discussion of impairment charges we recognized in 2006, 2005 and 2004.

Asset Retirement Obligations. We record the present value of our legal obligations to retire tangible, long-lived assets on our balance sheets as liabilities when the liability is incurred. Significant judgment is involved in estimating future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. Effective December 31, 2005, we adopted the provisions of FIN No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN No. 47) which is an interpretation of SFAS No. 143, “Asset Retirement Obligations”, (SFAS No. 143). Under the provisions of FIN No. 47, we recorded additional AROs to recognize the costs of the future removal of asbestos containing materials from certain of our power generation facilities. As a result, we recorded an after-tax charge of $5 million, which is included in the consolidated statements of operations as a cumulative effect of change in accounting principles. FIN No. 47, if it had been adopted as of January 1, 2004, would have had no material effect on our results of operations or earnings per share, and would have resulted in an additional $14 million of AROs included in our long-term liabilities at December 31, 2004.

In addition to the AROs discussed above, our AROs relate to activities such as ash pond and landfill capping, dismantlement of power generation facilities, closure and post-closure costs, environmental testing, remediation, monitoring and land and equipment lease obligations. Annual amortization of the assets associated with the AROs was $2 million each in 2006, 2005 and 2004. A summary of changes in our AROs is as follows:


	Year Ended December 31,
	2006			2005			2004
	(in millions)
Beginning of year	$	56		$	46		$	41
New ARO (1)		6			1			—
Accretion expense		6			4			5
Sale of DMSLP		—			(11	)		—
Implementation of FIN No. 47		—			16			—
Revision of previous estimate (2)		(12	)		—			—

End of year	$	56		$	56		$	46

F-11

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(1)

During 2006, we recorded additional AROs in the amount of $6 million related to our obligation to remediate a landfill located at our Danskammer generating facility. During 2005, we determined we would be obligated to dismantle our Danskammer generating facility upon its retirement. Therefore, we recorded an ARO in the amount of $1 million. There were no additional AROs, other than those recorded under the provisions of FIN No. 47, recorded or settled during 2006, 2005 or 2004.

(2)	During 2006, we revised our ARO obligation downward by $12 million based on revised estimates of the costs to remediate ash ponds at certain of our coal fired generating facilities.

We have additional potential retirement obligations for dismantlement of power generation facilities. Our current intent is to maintain these facilities in a manner such that they will be operated indefinitely. As such, we cannot estimate any potential retirement obligations associated with these assets. Liabilities will be recorded in accordance with SFAS No. 143 at the time we are able to estimate these AROs.

Contingencies, Commitments, Guarantees and Indemnifications. We are involved in numerous lawsuits, claims, proceedings and tax-related audits in the normal course of our operations. In accordance with SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5), we record a loss contingency 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 contingencies on an ongoing basis to ensure that we have appropriate reserves recorded on our consolidated balance sheets as required by SFAS No. 5. 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 judgment 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 estimates and judgments.

Liabilities for environmental contingencies 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 follow the guidance of FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN No. 45) for disclosures and accounting of various guarantees and indemnifications entered into during the course of business. When a guarantee or indemnification subject to FIN No. 45 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, however 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.

Intangible Assets. Intangible assets represent the fair value of assets, apart from goodwill, that arise from contractual rights or other legal rights. In accordance with SFAS No. 141, “Business Combinations” (SFAS No. 141), we record only those intangible assets that are distinctly separable from goodwill and can be sold, transferred, licensed, rented, or otherwise exchanged in the open market. Additionally, we recognize intangible assets for those assets that can be exchanged in combination with other rights, contracts, assets or liabilities.

F-12

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142), we initially record and measure intangible assets based on the fair value of those rights transferred in the transaction in which the asset was acquired. Those measurements are based on quoted market prices for the asset, if available, or measurement techniques based on the best information available such as a present value of future cash flows measurement. Present value measurement techniques involve judgments and estimates made by management about prices, cash flows, discount factors and other variables, and the actual value realized from those assets could vary materially from these judgments and estimates. We amortize our definite-lived intangible assets based on the useful life of the respective asset as measured by the life of the contract. If the intangible asset does not have a finite life based on the contractual or legal right, an estimate is made of the useful life based on the pattern in which the economic benefits of the asset are expected to be consumed. Intangible assets are also subjected to impairment testing when a triggering event occurs, and an impairment loss is recognized if the carrying amount of an intangible exceeds its fair value.

Revenue Recognition and Valuation of Risk Management Assets and Liabilities. We utilize two comprehensive accounting models in reporting our consolidated financial position and results of operations as required by GAAP—an accrual model and a fair value model. We determine the appropriate model for our operations based on guidance provided in applicable accounting standards and positions adopted by the FASB or the SEC. We have applied these accounting policies on a consistent basis during the three years in the period ended December 31, 2006.

The accrual model is used to account for substantially all of the operations conducted in our GEN-MW, GEN-NE and GEN-SO segments. These segments consist largely of the ownership and operation of physical assets that we use in various generation operations. We earn revenue from our facilities in three primary ways: (1) sale of energy generated by our facilities; (2) 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; and (3) sale of capacity. We recognize revenue from these transactions when the product or service is delivered to a customer.

The fair value model is used to account for forward physical and financial transactions which meet the definition of a derivative contract as defined by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended, (SFAS No.133). The criteria are complex, but generally require these contracts to relate to future periods, to contain fixed price and volume components and to have terms that require or permit net settlement of the contract in cash or the equivalent. SFAS No. 133 concluded that these contracts should be accounted for at fair value. In part, this conclusion is based on the cash settlement provisions in these agreements, as well as the volatility in commodity prices, interest rates and, if applicable, foreign exchange rates, which impact the valuation of these contracts. Since these transactions may be settled in cash or the equivalent, the value of the assets and liabilities associated with these transactions is reported at estimated settlement value based on current forward prices and rates as of each balance sheet date.

In order to estimate the fair value of our portfolio of transactions which meet the definition of a derivative and do not qualify for the “normal purchase normal sale” exception, we use a liquidation value approach

F-13

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

assuming that the ability to transact business in the market remains at historical levels. The estimated fair value of the portfolio is computed by multiplying all existing positions in the portfolio by estimated prices, reduced by a time value of money adjustment and reserves for credit and price. The estimated prices in this valuation are based either on (1) prices obtained from market quotes, when there are an adequate number of quotes to consider the period liquid, or, (2) if market quotes are unavailable or the market is not considered liquid, prices from a proprietary model which incorporates forward energy prices derived from market quotes and values from previously executed transactions. The amounts recorded as revenue change as these estimates are revised to reflect actual results and changes in market conditions or other factors, many of which are beyond our control.

Cash inflows and cash outflows associated with the settlement of risk management activities are recognized in net cash provided by (used in) operating activities on the consolidated statements of cash flows.

Income Taxes. We follow the guidance in SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109), which requires that we use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.

Please read Note 14—Income Taxes beginning on page F-42 for further discussion of our accounting for income taxes and any change in our valuation allowance.

Earnings Per Share. Basic earnings per share represents the amount of earnings for the period available to each share of common stock outstanding during the period. Diluted earnings per share amounts include the effect of issuing shares of common stock for outstanding stock options and performance based stock awards under the treasury stock method if including such potential common shares is dilutive.

Foreign Currency. For subsidiaries whose functional currency is not the U.S. Dollar, assets and liabilities are translated at year-end rates of exchange, and revenues and expenses are translated at monthly average exchange rates. Translation adjustments for the asset and liability accounts are included as a separate component of accumulated other comprehensive income in stockholders’ equity. Currency transaction gains and losses are recorded in other income and expense, net, on the consolidated statements of operations and totaled gains (losses) of approximately $1 million, ($4) million and $1 million for the years ended December 31, 2006, 2005 and 2004, respectively.

F-14

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Employee Stock Options. On January 1, 2003, we adopted the fair-value based method of accounting for stock-based employee compensation under SFAS No. 123, “Accounting for Stock-Based Compensation”, (SFAS No. 123) and used the prospective method of transition as described under SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure” (SFAS No. 148). Under the prospective method of transition, all stock options granted after January 1, 2003 were accounted for on a fair value basis. Options granted prior to January 1, 2003 continued to be accounted for using the intrinsic value method. Accordingly, for options granted prior to January 1, 2003, compensation expense was not reflected for employee stock options unless they were granted at an exercise price lower than market value on the grant date. We granted in-the-money options in the past and recognized compensation expense over the applicable vesting periods. No in-the-money stock options have been granted since 1999.

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123(R)) which revises SFAS No. 123. SFAS No. 123(R) requires all companies to expense the fair value of employee stock options and other forms of stock-based compensation. We adopted SFAS No. 123(R) effective January 1, 2006, using the modified prospective transition method permitted under this pronouncement. Our cumulative effect of implementing this standard, which consists entirely of a forfeiture adjustment, was less than $1 million after tax.

In November 2005, the FASB issued FSP No. 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards”. We have adopted the short-cut method to calculate the beginning balance of the APIC pool of the excess tax benefit, and to determine the subsequent impact on the APIC pool and unaudited condensed consolidated statements of cash flows of the tax effects of employee stock-based compensation awards that were outstanding upon our adoption of FAS 123(R). Utilizing the short-cut method, we have determined that we have a “Pool of Windfall” tax benefits that can be utilized to offset future shortfalls that may be incurred.

The adoption of SFAS No. 123(R) had no material impact on our consolidated statements of operations, our consolidated statements of cash flows and basic and diluted loss per share for the year ended December 31, 2006, compared to amounts that would have been reported pursuant to our previous accounting. Had compensation cost for all stock options granted prior to 2003 been determined on a fair value basis consistent with SFAS No. 123, our net income (loss) and basic and diluted earnings (loss) per share amounts would have approximated the following pro forma amounts for the years ended December 31, 2005 and 2004, respectively.


	Years Ended December 31,
	2005			2004
	(in millions, except per share data)
Net income (loss) as reported	$	90		$	(15	)
Add: Stock-based employee compensation expense included in reported net loss, net of related tax effects		6			4
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(8	)		(27	)

Pro forma net income (loss)	$	88		$	(38	)

Earnings (loss) per share:
Basic—as reported	$	0.18		$	(0.10	)
Basic—pro forma	$	0.17		$	(0.16	)
Diluted—as reported	$	0.18		$	(0.10	)
Diluted—pro forma	$	0.17		$	(0.16	)

F-15

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Please read Note 19—Capital Stock beginning on page F-55 for further discussion of our share-based compensation and expense recognized for 2006, 2005 and 2004.

Accounting Principles Adopted

SFAS No. 123(R). Please see Employee Stock Options beginning on page F-15 for information regarding our adoption of SFAS 123(R).

SFAS No. 153. In December 2004, the FASB issued SFAS No. 153, “ Exchanges of Nonmonetary Assets—An Amendment of APB Opinion No. 29” (SFAS No. 153). The guidance in APB Opinion No. 29, “ Accounting for Nonmonetary Transactions” (Opinion No. 29), is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in that Opinion, however, included certain exceptions to that principle. SFAS No. 153 amends Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. We adopted SFAS No. 153 on January 1, 2006. The adoption of this standard did not have a material effect on our results of operations, financial position or cash flows.

SFAS No. 154. In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections—A Replacement of APB Opinion No. 20 and SFAS No. 3” (SFAS No. 154). SFAS No. 154 changes the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. SFAS No. 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The provisions of SFAS No. 154 are effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. Adoption of this standard did not have a material effect on our results of operations, financial position or cash flows.

SFAS No. 158. On September 29, 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132 (R)” (SFAS No. 158). SFAS No. 158 requires employers to recognize the overfunded or underfunded status of a defined benefit or other postretirement plan (other than a multi-employer plan) as an asset or liability in its statement of financial position, and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. In addition, SFAS No. 158 requires employers to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. We adopted SFAS No. 158 on December 31, 2006 and recorded a pre-tax adjustment to accumulated other comprehensive income of approximately $56 million upon adoption. Please read Note 20—Employee Compensation, Savings and Pension Plans on page F-61 for further information.

SAB 108. On September 13, 2006, the SEC released SAB No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (SAB No. 108). SAB No. 108 states that a registrant’s materiality evaluation of an identified unadjusted error should quantify the effects of the identified unadjusted error on each financial statement and related financial statement disclosure. SAB No. 108 also states that registrants electing not to restate prior periods should reflect the effects of initially applying SAB No. 108 in their annual financial statements covering the first fiscal year ending after November 15, 2006. SAB No. 108 did not have a material effect on our results of operations, financial position or cash flows.

F-16

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

FSP FIN No. 45-3. In November 2005, the FASB issued FASB Staff Position No. 45-3, “Application of FASB Interpretation No. 45 to Minimum Revenue Guarantees Granted to a Business or Its Owners” (FSP FIN No. 45-3). It served as an amendment to FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”, by adding minimum revenue guarantees to the list of examples of contracts to which FIN No. 45 applies. Under FSP FIN No. 45-3, a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. FSP FIN No. 45-3 is effective for new minimum revenue guarantees issued or modified on or after January 1, 2006 and did not have a material effect on our results of operations, financial position or cash flows.

EITF Issue 05-6. In June 2005, the EITF reached consensus on Issue No. 05-6, “Determining the Amortization Period for Leasehold Improvements” (EITF Issue 05-6). EITF Issue 05-6 provides guidance on determining the amortization period for leasehold improvements acquired in a business combination or acquired subsequent to lease inception. The adoption of this standard on January 1, 2006 did not have a material effect on our results of operations, financial position or cash flows.

Accounting Principles Not Yet Adopted

FIN No. 48. On July 12, 2006, the FASB issued FIN No. 48, “Accounting for Uncertainty in Income Taxes” (FIN No. 48). FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109. FIN No. 48 prescribes a recognition threshold and measurement attributes for the financial statement recognition and measurement of an income tax position taken or expected to be taken in an income tax return. FIN No. 48 is effective for fiscal years beginning after December 15, 2006, and the cumulative effect of adopting FIN No. 48 will be recorded as an adjustment to retained earnings as of January 1, 2007. Additional guidance from the FASB on FIN No. 48 is pending. We are currently evaluating the impact of adopting FIN No. 48, but do not expect the adoption to have a material impact on our consolidated financial statements. However, the adoption will result in a decrease to our NOL carryforwards offset by equal changes to deferred tax liabilities or other deferred tax assets.

SFAS No. 157. On September 15, 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements. Accordingly, SFAS No. 157 does not require any new fair value measurements; however for some entities the application of SFAS No. 157 will change current practice. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact of this statement on our financial statements.

Note 3—Business Combinations and Acquisitions

LS Power. On September 14, 2006, we entered into a Plan of Merger, Contribution and Sale Agreement (the “Merger Agreement”) by and among Dynegy Inc., Dynegy Acquisition, Inc., a Delaware corporation (“New Dynegy”), Falcon Merger Sub Co., an Illinois corporation and a wholly owned subsidiary of New Dynegy (“Merger Sub”), LSP Gen Investors, L.P., LS Power Partners, L.P., LS Power Equity Partners PIE I, L.P., LS Power Associates, L.P., and LS Power Equity Partners, L.P. (collectively, the “LS Entities”), pursuant to which Merger Sub will be merged with and into us, as a result of which we will become a wholly-owned subsidiary of New Dynegy.

A portion of the LS Entities’ operating generation portfolio will be combined with our generating assets and operations, and New Dynegy will acquire a 50 percent ownership interest in a development company that is

F-17

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

currently controlled by the LS Entities. Upon completion of the merger agreement, each share of our Class A Common Stock and our Class B Common Stock will be converted into the right to receive one share of New Dynegy Class A Common Stock, par value $0.01 per share (“New Dynegy Class A Common Stock”).

If the transaction is consummated, the LS Entities will contribute certain interests in power generation assets to New Dynegy in exchange for (i) 340 million shares of New Dynegy Class B Common Stock, par value $0.01 per share (“New Dynegy Class B Common Stock” and, together with New Dynegy Class A Common Stock, the “New Dynegy Common Stock”), (ii) $100 million in cash, and (iii) $275 million in aggregate principal amount of notes payable to be issued by New Dynegy.

Under the terms of the Merger Agreement, we and the LS Entities agreed not to (i) solicit proposals relating to alternative business combination transactions or (ii) subject to certain exceptions, enter into discussions or an agreement concerning or provide confidential information in connection with any proposals for alternative business combination transactions. The Merger Agreement provides certain termination rights to both us and the LS Entities, and further provides that, upon termination of the Merger Agreement under certain circumstances, (i) we may be required to pay the LS Entities or (ii) the LS Entities may be required to pay us, an aggregate termination fee of $100 million, as described in the Merger Agreement. The affirmative vote of two-thirds of the (i) issued and outstanding shares of our Class A Common Stock voting as a class, (ii) issued and outstanding shares of our Class B Common Stock voting as a class and (iii) issued and outstanding shares of our Common Stock voting together as a class is required to approve the merger. Assuming all necessary conditions are satisfied, which cannot be guaranteed, the transaction is expected to close at the end of the first quarter 2007.

Kendall Power. On September 14, 2006, the LS Entities and Kendall Power LLC (“Kendall Power”), a newly formed wholly owned subsidiary of Dynegy, entered into a Limited Liability Company Membership Interests and Stock Purchase Agreement (the “Kendall Agreement”) pursuant to which Kendall Power agreed to acquire all of the outstanding interests in LSP Kendall Holdings, LLC for $200 million in cash, as adjusted for certain changes in working capital. The closing of the Kendall Agreement will occur only if closing does not occur with respect to the transactions contemplated by the Merger Agreement. We have agreed to guarantee certain of Kendall Power’s obligations under the Kendall Agreement. Please read Note 17—Commitments and Contingencies—Guarantees and Indemnifications—Kendall Guarantee beginning on page F-51 for further discussion.

Rocky Road. On March 31, 2006, contemporaneous with our sale of our interest in WCP (Generation) Holdings LLC (“West Coast Power”) (please read Note 4— Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—West Coast Power), we completed our acquisition of NRG’s 50% ownership interest in Rocky Road Power, LLC (“Rocky Road”), the entity that owns the Rocky Road power plant, a 330-megawatt natural gas-fired peaking facility near Chicago (of which we already owned 50%), for proceeds of $165 million, net of cash acquired. As a result of the transaction, we became the primary beneficiary of the entity as provided under the guidance in FIN No. 46(R), “Consolidation of Variable Interest Entities an interpretation of ARB No. 51”, and thus consolidated the assets and liabilities of the entity at March 31, 2006. Please read Note 10—Unconsolidated Investments—Variable Interest Entities for further discussion.

Sithe Energies. On January 31, 2005, we acquired 100% of the outstanding common shares of ExRes SHC, Inc. (“ExRes”), the parent company of Sithe Energies, Inc. (“Sithe Energies”) and Sithe/Independence Power Partners, L.P. (“Independence”). The results of the operations of ExRes have been included in our consolidated financial statements since that date. Through this acquisition, we acquired the 1,064 MW Independence power

F-18

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

generation facility located near Scriba, New York, as well as natural gas-fired merchant facilities in New York and hydroelectric generation facilities in Pennsylvania. We have not consolidated the entities that own these four natural gas-fired facilities and four hydroelectric generation facilities, in accordance with the provisions of FIN No. 46R. See Note 10—Unconsolidated Investments—Variable Interest Entities beginning on page F-33 for additional discussion of these facilities. In addition to these power plants, we acquired the 740 MW firm capacity sales agreement between Independence and Con Edison, a subsidiary of Consolidated Edison, Inc. This agreement, which runs through 2014, will provide us with annual cash receipts of approximately $100 million, subject to the restrictions on distribution under Independence’s indebtedness. Revenue from this capacity obligation is largely fixed with a variable discount that varies each month based on the price of power at Pleasant Valley LMP. Independence holds power tolling, financial swap and other contracts with other Dynegy subsidiaries. Because of the acquisition, these contracts have become intercompany agreements, and their financial statement impact has been substantially eliminated. This transaction enabled us to address one of our outstanding power tolling arrangements and to expand our generation capacity in a market where we have an existing presence.

The aggregate purchase price was comprised of (i) $135 million cash, which was reduced by a purchase price adjustment of approximately $2 million; (ii) transaction costs of approximately $16 million, approximately $3 million of which were paid in 2004; and (iii) the assumption of $919 million of face value project debt, which was recorded at its fair value of $797 million as of January 31, 2005. Please read Note 12—Debt—Sithe Energies Debt beginning on page F-39 for additional information regarding the debt assumed.

The allocation of purchase price to specific assets and liabilities is based, in part, upon outside appraisals using customary valuation procedures and techniques. That allocation changed during the fourth quarter 2005 after we received information related to investment valuations and tax basis balances. The acquisition resulted in an excess of the fair value of assets acquired over cost of the acquisition. This excess was then allocated to property, plant and equipment and intangible assets acquired, including intangible assets arising from contracts with us, on a pro-rata basis. The following table summarizes the fair values of the assets and liabilities acquired at the date of acquisition, January 31, 2005 (in millions):


Other current assets	$	88
Restricted cash and investments		132
Property, plant and equipment		353
Assets from risk-management activities		62
Intangible assets		657
Other assets		4

Total assets acquired	$	1,296

Current liabilities	$	(98	)
Deferred income taxes		(193	)
Other long-term liabilities		(59	)
Long-term debt		(797	)

Total liabilities assumed	$	(1,147	)

Net assets acquired	$	149

Included in the assets acquired are restricted cash and investments of approximately $132 million. The restricted investments include Federal Home Loan Bank Bonds, U.S. Treasury Bonds, and high-grade short-term commercial paper. The restricted cash and investments are related to a sinking fund required by Independence’s debt instruments, including a major overhaul reserve, a debt service reserve, a principal payment reserve, an

F-19

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

interest reserve and a project restoration reserve. Restrictions on the cash and investments are scheduled to be lifted at the end of the project financing term in 2014. For further discussion, please read Note 12—Debt—Sithe Energies Debt beginning on page F-39.

Of the $657 million of acquired intangible assets, $488 million was allocated to the firm capacity sales agreement with Con Edison. This asset will be amortized on a straight-line basis over the remaining life of the contract as a reduction to revenue in our consolidated statements of operations, through October 2014. In addition, Independence holds a power tolling contract and a natural gas supply agreement with another of our subsidiaries, which were valued at $153 million and $16 million, respectively, as of January 31, 2005. Upon completion of our purchase of Independence, the power tolling agreement and the natural gas supply agreement were effectively settled, which resulted in a 2005 charge equal to their fair values, in accordance with EITF Issue 04-01, “Accounting for Pre-existing Contractual Relationships Between the Parties to a Purchase Business Combination”. As a result, we recorded a 2005 pre-tax charge of $169 million, which is included in cost of sales on our consolidated statements of operations. Upon settlement of the power tolling and natural gas supply agreements, the firm capacity sales agreement with Con Edison is the only remaining intangible asset associated with the acquisition of ExRes, which is included in intangibles and prepaids and other current assets on our consolidated balance sheets.

We exercised our right to require Exelon to decommission, sell, or otherwise dispose of all four natural gas-fired merchant facilities owned by ExRes. Under the terms of the purchase agreement, Exelon was to direct the disposition of these facilities and indemnify us with respect to all past and present operations. On June 1 and August 4, 2005 we entered into agreements, as directed by Exelon, to sell the ownership and operating interests in the facilities. The transactions, which were approved by the FERC and the New York Public Service Commission, closed on October 31, 2005 and had no impact on our consolidated financial statements as Exelon received the proceeds from the sale. Further, Exelon is entitled to cause us to decommission, sell, or bankrupt any or all of the four hydroelectric facilities owned by ExRes, for which we have been indemnified for any losses.

Note 4—Dispositions, Contract Terminations and Discontinued Operations

Dispositions and Contract Terminations

Rockingham. On November 9, 2006, we completed the sale to Duke Energy Carolinas, LLC (a subsidiary of Duke Energy) (“Duke Power”) of our Rockingham facility, a peaking facility in North Carolina, which is included in our GEN-SO reportable segment, for $194 million in cash. A portion of the proceeds from the sale were used to repay our borrowings under the $150 million Term Loan, with the remaining proceeds used as an additional source of liquidity. Please read Note 12—Debt—Fourth Amended and Restated Credit Facility beginning on page F-36 for further discussion of the Term Loan.

Beginning in the second quarter 2006, Rockingham met the held for sale classification requirements of SFAS No. 144, and continued to meet the requirements through the closing of the sale on November 9, 2006. SFAS No. 144 requires that long-lived assets not be depreciated or amortized while they are classified as held for sale. As a result, we discontinued depreciation and amortization of Rockingham's property, plant and equipment during the second quarter 2006. Depreciation and amortization expense related to Rockingham totaled $2 million, $6 million and $6 million in the years ended December 31, 2006, 2005 and 2004, respectively. In addition, SFAS No. 144 requires a loss to be recognized if assets held for sale less liabilities held for sale are in excess of fair value less costs to sell. Accordingly, we recorded a pre-tax impairment of $9 million in the year ended December 31, 2006 which is included in Impairment and other charges on our consolidated statements of operations.

West Coast Power. On March 31, 2006, contemporaneous with our purchase of Rocky Road (please read Note 3—Business Combinations and Acquisitions—Rocky Road on page F-18), we completed the sale to NRG of our 50% ownership interest in West Coast Power, a joint venture between us and NRG which has ownership interests in the West Coast Power power plants in southern California totaling approximately 1,800 megawatts, for proceeds of approximately $165 million, net of cash acquired. We did not recognize a material gain or loss on the sale. Pursuant to our divestiture of West Coast Power, we no longer maintain a significant variable interest in the entity as provided by the guidance in FIN No. 46(R). Please read Note 10—Unconsolidated Investments—Variable Interest Entities on page F-33 for further discussion.

F-20

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Sterlington Contract Termination. In December 2005, we entered into an agreement to terminate the Sterlington long-term wholesale power tolling contract with Ouachita Power LLC (“Ouachita”), a joint venture of GE Energy Financial Services and Cogentrix Energy, Inc. Under the terms of the agreement, we paid Ouachita approximately $370 million in March 2006 to eliminate approximately $449 million in capacity payment obligations through 2012 and avoid approximately $295 million in additional capacity payment obligations that would arise if Ouachita exercised its option to extend the contract through 2017. We recognized a pre-tax charge of approximately $364 million ($229 million after-tax) in 2005 related to this transaction.

Sale of Illinois Power. On September 30, 2004, we sold all of our outstanding common and preferred shares of Illinois Power Company, which formerly comprised our REG segment, as well as our 20% interest in the Joppa power generation facility, to Ameren Corporation for $2.3 billion.

During 2005, we paid approximately $5 million to Ameren for a final working capital purchase price adjustment. As a result of an adjustment to the contingent liabilities identified as part of the Illinois Power sale, we recorded a $12 million charge in 2005 and we paid $8 million in partial satisfaction of such contingent liabilities. For further discussion, please read Note 17—Commitments and Contingencies—Guarantees and Indemnifications—Illinois Power Indemnities beginning on page F-52. The adjustment to the contingent liabilities resulted in an increase to our capital loss carryforward, and a corresponding increase to the deferred tax valuation allowance of $4 million.

During 2004, Illinois Power met the held for sale classification requirements of SFAS No. 144, and continued to meet the requirements through the closing of the sale on September 30, 2004. We discontinued depreciation and amortization of Illinois Power’s property, plant and equipment and regulatory assets, effective February 1, 2004. Depreciation and amortization expense related to Illinois Power totaled $10 million the year ended December 31, 2004. In addition, SFAS No. 144 requires a loss to be recognized by the amount Assets held for sale less Liabilities held for sale are in excess of fair value less costs to sell. Accordingly, we recorded a pre-tax loss on the sale of $112 million in the year ended December 31, 2004. Of the charge, $58 million is reflected in gain (loss) on sale of assets, net and $54 million of the charge is reflected in impairment and other charges on our consolidated statements of operations.

Further, pursuant to SFAS No. 144, we are not reporting the results of Illinois Power’s operations as a discontinued operation. If we were to account for Illinois Power as a discontinued operation, its results of operations would be condensed into income from discontinued operations, net of taxes, on our consolidated statements of operations, and prior periods would be required to be restated to conform to this presentation. To qualify for discontinued operations classification, SFAS No. 144 and subsequent interpretations, specifically EITF Issue 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations”, require that the seller have no significant continuing involvement with the business being sold. However, we sold capacity and energy to Illinois Power under a two-year power purchase agreement which began in January 2005. Consequently, because we still had significant continuing involvement with Illinois Power, we continued to include the historical results of Illinois Power’s operations as part of our continuing operations. Additionally, power sales to Illinois Power occurring subsequent to the disposition are reported in our consolidated statements of operations as third party sales. Approximately $466 million, $459 million and $109 million of revenues, derived from power sales to Illinois Power occurring subsequent to the disposition, are reflected in our continuing operations for the periods ending December 31, 2006, 2005 and 2004, respectively.

Had the results of Illinois Power been excluded from our comparative results as though the sale had occurred at the beginning of 2004, our revenues; loss before cumulative effect of changes in accounting principles, net of tax; net income (loss) applicable to common stockholders; and associated basic and diluted earnings (loss) per share would have approximated the following pro forma amounts for the year ended December 31, 2004 (in millions, except per share data):

F-21

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


Revenues:
As reported	$	2,451
Pro forma		1,658

Loss before cumulative effect of change in accounting principles, net of tax:
As reported	$	(15	)
Pro forma		(32	)

Net loss applicable to common stockholders:
As reported	$	(37	)
Pro forma		(54	)

Loss per share—Loss before cumulative effect of change in accounting principles, net of tax:
Basic—as reported	$	(0.10	)
Basic—pro forma	$	(0.14	)
Diluted—as reported	$	(0.10	)
Diluted—pro forma	$	(0.14	)

Loss per share—Net loss applicable to common stockholders:
Basic—as reported	$	(0.10	)
Basic—pro forma	$	(0.14	)
Diluted—as reported	$	(0.10	)
Diluted—pro forma	$	(0.14	)

Joppa. In September 2004, we recorded a pre-tax gain of $75 million upon closing of the sale of our 20% interest in the Joppa power generating facility. This gain is included in earnings (losses) from unconsolidated investments on our consolidated statements of operations.

Sherman. In November 2004, we sold our Sherman natural gas processing facility located in Sherman, Texas. This sale resulted in a pre-tax gain of approximately $16 million. This gain is included in income from discontinued operations on our consolidated statements of operations.

Indian Basin. In April 2004, we sold our 16% interest in the Indian Basin Gas Processing Plant for approximately $48 million, and we recognized a pre-tax gain on the sale of approximately $36 million. This gain is included in income from discontinued operations on our consolidated statements of operations.

PESA. In April 2004, we sold our interest in the Plantas Eolicas, S.A. de R.L. 20 MW wind-powered electric generation facility located in Costa Rica for approximately $11 million. We recognized a pre-tax loss of approximately $1 million on the sale. This loss is included in gain (loss) on sale of assets, net on our consolidated statements of operations.

Kendall. In November 2004, DPM entered into a “back to back” power purchase agreement with Constellation Energy Commodities Group, Inc. (“Constellation”) under which Constellation will effectively receive DPM’s rights to purchase approximately 570 MW of capacity and energy arising under DPM’s tolling contract with LSP-Kendall Energy, LLC for a four-year term from December 2004 through November 2008. DPM will remain the primary obligor under the Kendall tolling contract, but will receive offsetting payments from Constellation during the four-year term.

In connection with this transaction, DPM paid Constellation $117.5 million in cash and effectively eliminated approximately $161 million of our future fixed payment obligations under the Kendall tolling contract through November 2008. We recognized a pre-tax charge of approximately $115 million ($72 million after-tax) related to this transaction. The charge is included in cost of sales on the consolidated statements of operations.

F-22

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Gas Transportation Contracts. In June 2004, we agreed to exit four long-term natural gas transportation contracts whose purpose was to secure firm pipeline capacity through 2014 in support of our former third party marketing and trading business. In exchange for exiting these obligations, we paid $20 million in June 2004, $16 million in December 2004 and $26 million in March 2005. This payment obligation was recorded at its fair value of $40 million and was accreted to $42 million over the period July 1, 2004 through March 31, 2005. Additionally, we reversed an aggregate liability of $148 million associated with the transportation contracts that was originally established in 2001 and recognized a pre-tax gain of $88 million related to these transactions. This gain is included in revenues on our consolidated statements of operations and is included in the results of our CRM segment. This agreement eliminated our obligation to make approximately $295 million in aggregate fixed capacity payments from April 2005 through 2014.

Discontinued Operations

Calcasieu. On January 31, 2007, we entered into an agreement to sell our interest in the Calcasieu power generation facility to Entergy Gulf States, Inc. (“Entergy”) for approximately $57 million, subject to regulatory approval. The transaction is expected to close in early 2008. We recorded a pre-tax impairment of approximately $36 million in the year ended December 31, 2006, which was included in Discontinued operations on our consolidated statements of operations. Please read Note 5—Restructuring and Impairment Charges—Asset Impairments on page F-24 for further discussion. Pursuant to SFAS No. 144, we are reporting the results of Calcasieu as a discontinued operation. Accordingly, the operations of Calcasieu have been included in discontinued operations for all periods presented.

Natural Gas Liquids. On October 31, 2005, we completed the sale of DMSLP, which comprised substantially all remaining operations of our NGL business, to Targa and two of its subsidiaries for $2.44 billion in cash.

In 2006, we received $15 million from Targa which represents the final portion of the sales price owed to us.

Pursuant to SFAS No. 144, we are reporting the results of NGL’s operations as a discontinued operation. Accordingly, the results of operations of our NGL business have been included in discontinued operations for all periods presented. EITF Issue 87-24, “Allocation of Interest to Discontinued Operations” (EITF Issue 87-24) requires that interest expense on debt that was required to be repaid upon the sale of DMSLP should be reclassified to discontinued operations. Therefore, interest expense on our former term loan and our former generation facility debt was allocated to discontinued operations, as the respective debt instruments were paid upon the sale of DMSLP. Such interest expense, inclusive of amortization of debt issuance costs, totaled $53 million and $27 million for the years ended December 31, 2005 and 2004, respectively.

Additionally, results from NGL’s operations include revenues and cost of sales arising from intersegment transactions, which ceased after the sale of DMSLP. NGL processed natural gas and sold this natural gas to CRM for resale to third parties. NGL also purchased natural gas from CRM and electricity from GEN. As the intersegment revenues and cost of sales included in NGL’s results were reclassified to discontinued operations, the effects of these intersegment transactions eliminated in consolidation, including the ultimate third-party settlement, previously recorded in other segments, were also reclassified to discontinued operations.

Other. We sold or liquidated some of our operations during 2003, including DGC (our communications business) and our U.K. CRM business, which have been accounted for as discontinued operations under SFAS No. 144.

F-23

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table summarizes information related to our discontinued operations, including Calcasieu and the NGL business operations discussed above:


	Calcasieu			U.K. CRM			DGC		NGL		Total
	(in millions)
2006
Revenue	$	1		$	—		$	—	$	—	$	1
Income (loss) from operations before taxes		(39	)		23			1		6		(9	)
Income (loss) from operations after taxes		(28	)		19			1		4		(4	)

2005
Revenue	$	2		$	—		$	—	$	4,125	$	4,127
Income from operations before taxes		(3	)		6			—		163		166
Income (loss) from operations after taxes		(2	)		(1	)		2		223		222
Gain on sale before taxes		—			—			—		1,087		1,087
Gain on sale after taxes		—			—			—		675		675

2004
Revenue	$	7		$	—		$	—	$	3,753	$	3,760
Income from operations before taxes		—			19			3		254		276
Income (loss) from operations after taxes		—			(7	)		2		170		165

In 2006, we recognized approximately $21 million of pre-tax income associated with a U.K. CRM receivable previously reserved that is now expected to be collected. We also recorded a $36 million impairment for the Calcasieu generation facility. Please read Note 5—Restructuring and Impairment Charges—Asset Impairments for further discussion.

In 2005, we recognized $3 million of pre-tax income primarily associated with U.K. CRM’s receipt of a third party bankruptcy settlement, offset by foreign currency exchange losses.

In 2004, we recognized $17 million of pre-tax income related to translation gains on foreign currency in the U.K. Please read Note 6—Risk Management Activities and Financial Instruments—Accounting for Derivative Instruments and Hedging Activities—Net Investment Hedges In Foreign Operations beginning on page F-27 for further discussion. Also in 2004, we recognized $3 million of pre-tax income associated with DGC’s receipt of $3 million from a third party in settlement of a prior contractual claim and a tax expense of $20 million related to charges resulting from the conclusion of prior year tax audits.

Note 5—Restructuring and Impairment Charges

Asset Impairments. At September 30, 2006, we tested the Bluegrass generation facility for impairment based on the FERC's recent approval and Louisville Gas and Electric’s (“LG&E”) completion of various compliance steps to allow it to withdraw from participation in the MISO market as of September 1, 2006. The Bluegrass facility has historically sold power into the MISO market through transmission provided by LG&E. This change will limit our ability or increase the cost to deliver power to the MISO market. After testing, we recorded a pre-tax impairment charge of $96 million ($61 million after-tax) in the GEN-MW segment. This charge is included in Impairment and other charges in our consolidated statements of operations. We determined the fair value of the facility using the expected present value technique.

At December 31, 2006, we determined that it was more likely than not that certain assets would be sold prior to the end of their previously estimated useful lives. Therefore, impairment analyses were performed and we recorded a total pre-tax impairment charge of $50 million ($32 million after tax). Of this charge, $36 million relates to the Calcasieu facility and is recorded in the GEN-SO segment in Discontinued operations. The remaining $14 million relates to the Bluegrass facility and is recorded in the GEN-MW segment. This charge is included in Impairment and other charges in our consolidated statements of operations. We determined the fair value of the Bluegrass facility using the expected present value technique. We determined the fair value of the Calcasieu facility based on the purchase price in the sales agreement.

F-24

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In 2006, we recorded a $9 million pre-tax impairment of our investment in Black Mountain. Please read Note 10—Unconsolidated Investments—Power Generation—South Investments beginning on page F-32 for further discussion.

In 2005, we recorded $13 million, $10 million and $4 million in pre-tax impairments of our investments in Black Mountain, West Coast Power and Panama, respectively. Please read Note 10—Unconsolidated Investments—Power Generation—South Investments beginning on page F-32 for further discussion. Also in 2005, we recorded in GEN-MW an impairment of an unused turbine totaling $29 million. We determined the fair value of the turbine based on market prices of similar assets available for sale. Also in 2005, we recorded severance and restructuring charges totaling $11 million. For further information, please read “2005 Restructuring” below. Finally, in connection with our sale of DMSLP, included in discontinued operations, were charges of $3 million and $2 million for cancellation fees and operating leases, respectively.

In 2004, we recorded a $112 million pre-tax impairment of our interest in Illinois Power. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Sale of Illinois Power beginning on page F-21 for further discussion. In addition, during 2004, we recorded a $5 million pre-tax charge related to the impairment of one of our NGL assets. Also during 2004, we recorded $85 million in pre-tax impairments of our investment in West Coast Power. Please read Note 10—Unconsolidated Investments—Power Generation—South Investments beginning on page F-32 for further discussion.

2005 Restructuring. In December 2005, in order to better align our corporate cost structure with a single line of business and as part of a comprehensive effort to reduce on-going operating expenses, we implemented a restructuring plan (the “2005 Restructuring Plan”). The 2005 Restructuring Plan resulted in a reduction of approximately 40 positions and was complete by June 30, 2006. We recognized a pre-tax charge of $11 million in the fourth quarter 2005. We recognized approximately $2 million of charges in the year ended December 31, 2006, when transitional services were completed by certain affected employees. These charges related entirely to severance costs.

The following is a schedule of 2006 activity for the severance liabilities recorded in connection with this restructuring (in millions):


Balance at December 31, 2005	$	9
2006 adjustments to liability		2
Cash payments		(11	)

Balance at December 31, 2006	$	—

F-25

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2002 Restructuring. In October 2002, we announced a restructuring plan (the “2002 Restructuring Plan”) designed to improve operational efficiencies and performance across our lines of business. The following is a schedule of 2006, 2005 and 2004 activity for the 2002 Restructuring Plan liabilities recorded associated with the severance, cancellation fees and operating leases:


	Severance			Cancellation Fees and Operating Leases			Total
	(in millions)
Balance at December 31, 2003	$	23		$	30		$	53
2004 adjustments to liability		18			7			25
2004 cash payments		(38	)		(12	)		(50	)

Balance at December 31, 2004		3			25		$	28
2005 cash payments		—			(9	)		(9	)

Balance at December 31, 2005		3			16			19
2006 adjustments to liability		—			(1	)		(1	)
2006 cash payments		—			(8	)		(8	)

Balance at December 31, 2006	$	3		$	7		$	10

During 2004, the adjustment to the accrued liability primarily reflects increases in the severance accrual due to changes in our estimate of the probable loss associated with the severance claims of our former chief executive officer and our former president. Cash payments during 2004 reflect payments made to our former chief executive officer and our former president.

In addition to the $7 million accrual above, we have a $1 million accrual for operating leases made in connection with the sale of DMSLP. We expect these amounts to be paid by the end of 2007 when the leases expire. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Natural Gas Liquids beginning on page F-23 for further information.

Note 6—Risk Management Activities and Financial Instruments

Our operations are impacted by several factors, some of which may not be mitigated by risk management methods. These risks include, but are not limited to, commodity price, interest rate and foreign exchange rate fluctuations, weather patterns, counterparty credit risks, changes in competition, operational risks, environmental risks and changes in regulations.

We define market risk as changes to our earnings and cash flow resulting from changes in market conditions, including changes in commodity prices, interest rates and currency rates as well as the impact of volatility and market liquidity on such prices. We seek to manage market risk through diversification, controlling position sizes and executing hedging strategies.

Accounting for Derivative Instruments and Hedging Activities

We follow the accounting and disclosure requirements of SFAS No. 133, as amended. Under SFAS No. 133, all derivative instruments are recognized in the balance sheet at their fair values and changes in fair value are recognized immediately in earnings, unless such instruments qualify, and are designated, as hedges of future cash flows, fair values or net investments in foreign operations or qualify, and are designated, as normal purchases and sales.

F-26

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Cash Flow Hedges. We enter into financial derivative instruments that qualify as cash flow hedges. The maximum length of time for which we have hedged our exposure for cash flow hedges is through 2008. Instruments related to our generation business are entered into for purposes of hedging future fuel requirements and forecasted sales transactions. Interest rate swaps were previously used to convert the floating interest-rate component of some obligations to fixed rates.

Any ineffective portion of a cash flow hedge is reported immediately as a component of income in the consolidated statements of operations. Ineffectiveness associated with cash flow hedges of commodity transactions and interest rate swaps is included in revenues and other income and expense, net, respectively. During the years ended December 31, 2006, 2005 and 2004, we recorded $7 million, $3 million and $(3) million of income (expense), respectively, related to ineffectiveness from changes in fair value of hedge positions. No amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows in any of the periods.

During the years ended December 31, 2006, 2005 and 2004 no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.

The balance in cash flow hedging activities, net at December 31, 2006 is expected to be reclassified to future earnings, contemporaneously with the related purchases of fuel or sales of electricity, as applicable to each type of hedge. Of this amount, after-tax gains of approximately $72 million are currently estimated to be reclassified into earnings in 2007. The actual amounts that will be reclassified to earnings over this period and beyond could vary materially from this estimated amount as a result of changes in market prices, hedging strategies, the probability of forecasted transactions occurring and other factors.

Fair Value Hedges. We also enter into derivative instruments that qualify as fair value hedges. We use interest rate swaps to convert a portion of our non-prepayable fixed-rate debt into variable-rate debt. The maximum length of time for which we have hedged our exposure for fair value hedges is through 2012. During the years ended December 31, 2006, 2005 and 2004, there was no ineffectiveness from changes in the fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. During each of the years ended December 31, 2006, 2005 and 2004, there were no gains or losses related to the recognition of firm commitments that no longer qualified as fair value hedges.

Net Investment Hedges In Foreign Operations. Although we have exited a substantial amount of our foreign operations, we have remaining investments in foreign subsidiaries, the net assets of which are exposed to currency exchange-rate volatility. As of December 31, 2006, 2005 and 2004 we had no net investment hedges in place to hedge that exposure.

During 2003, our efforts to exit the U.K. CRM business and the European communications business were substantially completed. As required by SFAS No. 52, “Foreign Currency Translation,” a significant portion of unrealized gains and losses resulting from translation and financial instruments utilized to hedge currency exposures previously recorded in stockholders’ equity were recognized in income, resulting in an after-tax loss of approximately $16 million. During 2004, we repatriated a majority of our cash from the U.K. by repayment of intercompany loans, resulting in the substantial liquidation of our investment in the U.K. As a result, we recognized approximately $17 million of pre-tax translation gains in income that arose since April 1, 2003 and had accumulated in stockholders’ equity.

F-27

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Accumulated Other Comprehensive Income. Accumulated other comprehensive income, net of tax, is included in stockholders’ equity on the consolidated balance sheets as follows:


	December 31,
	2006			2005
	(in millions)
Cash flow hedging activities, net	$	76		$	(2	)
Foreign currency translation adjustment		23			24
Minimum pension liability		—			(18	)
Unrecognized prior service cost and actuarial loss		(43	)		—