Edgar Filing: DYNEGY INC /IL/

Amendment No. 1 to Form 10-K for period ending December 31, 2005

Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

Amendment No. 1

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 1-15659

DYNEGY INC.

(Exact name of registrant as specified in its charter)

Illinois

74-2928353

(State or other jurisdiction

of incorporation or organization)

(I.R.S. Employer

Identification No.)

1000 Louisiana, Suite 5800

Houston, Texas 77002

(Address of principal executive offices)

(713) 507-6400

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered
Class A common stock, no par value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:


Title of each class
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.


Large accelerated filer x		Accelerated filer ¨		Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

As of June 30, 2005, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $1,371,862,531 based on the closing sale price as reported on the New York Stock Exchange.

Number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: Class A common stock, no par value per share 304,618,018 shares outstanding as of March 7, 2006; Class B common stock, no par value per share, 96,891,014 shares outstanding as of March 7, 2006.

DOCUMENTS INCORPORATED BY REFERENCE. Part III (Items 10, 11, 12, 13 and 14) incorporates by reference portions of the Notice and Proxy Statement for the registrant’s 2006 Annual Meeting of Shareholders, which will be filed not later than 120 days after December 31, 2005.

Index to Financial Statements

DYNEGY INC. FORM 10-K/A

INTRODUCTORY NOTE

Dynegy Inc. is filing this Amendment No. 1 on Form 10-K/A (“Amendment No. 1”) to reflect the effect of a $13 million decrease to our income from discontinued operations for the year ended December 31, 2005 and a $13 million increase to our net deferred tax liability at December 31, 2005 on our historical consolidated financial statements and related information, as reported in our Annual Report on Form 10-K for the fiscal year ended December 31, 2005, which was originally filed on March 15, 2006 (the “Original Filing”).

The aforementioned item includes adjustments previously announced by us in our Current Report on

Form 8-K dated May 1, 2006 and is discussed in more detail in the Restatement Note to the accompanying consolidated financial statements beginning on page F-10. The following items of the Original Filing are amended by this Amendment No. 1:

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

Item 9A. Controls and Procedures

Item 15. Exhibits, Financial Statement Schedules

Unaffected items have not been repeated in this Amendment No. 1.

PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS AMENDMENT NO. 1, INCLUDING THE FINANCIAL STATEMENTS AND THE NOTES THERETO, DOES NOT REFLECT EVENTS OCCURRING AFTER THE DATE OF THE ORIGINAL FILING, WITH THE EXCEPTION OF THE ITEM DISCUSSED ABOVE. SUCH EVENTS INCLUDE, AMONG OTHERS, THE EVENTS DESCRIBED IN OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO. FOR A DESCRIPTION OF THESE EVENTS, PLEASE READ OUR EXCHANGE ACT REPORTS FILED SINCE MARCH 15, 2006.

The Original Filing also reflects the effect of the restatement of our consolidated balance sheet as of December 31, 2004 and periods prior to 2004 as a result of adjustments to our deferred income tax accounts, as reported in our Annual Report of Form 10-K for the year ended December 31, 2004, which was filed on March 14, 2005.

As previously disclosed in our 2004 Form 10-K, we undertook an evaluation of our tax accounting and reconciliation controls and processes, including a tax basis balance sheet review, which resulted in an adjustment to our deferred tax liability balance. We have since identified mistakes in the tax basis balance sheet review, which totaled an $89 million overstatement of the deferred tax liability balance. Although these mistakes were not considered material, either individually or in the aggregate, to the period to which they related, the mistakes are material, in the aggregate, to our 2005 results. We are required to restate prior periods in accordance with APB 20, “Accounting Changes.” The item is discussed in more detail in the Explanatory Note to the accompanying consolidated financial statements beginning on page F-10. The following Items of our Original Filing for the year ended December 31, 2005, were affected by this item:

Item 6. Selected Financial Data

Item 8. Financial Statements and Supplementary Data

Please read Item 9A. Controls and Procedures for a discussion of our control deficiencies related to the deferred income tax accounts and the preparation and review of adjustments to such accounts.

Index to Financial Statements

DYNEGY INC.

FORM 10-K/A

TABLE OF CONTENTS


		Page
	PART I
Definitions		1

	PART II
Item 6.	Selected Financial Data	2
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	4
Item 8.	Financial Statements and Supplementary Data	47
Item 9A.	Controls and Procedures	47

	PART IV
Item 15.	Exhibits, Financial Statement Schedules	49
Signatures		59

Index to Financial Statements

PART I

DEFINITIONS

As used in this Form 10-K/A, the abbreviations contained herein have the meanings set forth in the glossary beginning on page
F-86. Additionally, the terms “Dynegy,” “we,” “us” and “our” refer to Dynegy Inc. and its subsidiaries, unless the context clearly indicates otherwise.

Index to Financial Statements

PART II

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.

As discussed in the Restatement Note to the accompanying Consolidated Financial Statements, the accompanying Consolidated Financial Statements have been restated since the date of the Original Filing. In addition, as discussed in the Explanatory Note to the accompanying Consolidated Financial Statements, the historical information in the accompanying Consolidated Financial Statements of the Original Filing had been restated. Please read the Restatement Note and Explanatory Note to the accompanying Consolidated Financial Statements beginning on page F-10 for additional information about these restatements. The selected financial data that follows has been adjusted to reflect these restatements.

Dynegy’s Selected Financial Data


	Year Ended December 31,
	2005			2004			2003			2002			2001
	(restated)
	(in millions, except per share data)
Statement of Operations Data (1):
Revenues	$	2,313		$	2,451		$	2,599		$	2,109		$	3,635
Depreciation and amortization expense		(220	)		(235	)		(373	)		(378	)		(368	)
Goodwill impairment		—			—			(311	)		(814	)		—
Impairment and other charges		(46	)		(78	)		(225	)		(176	)		—
General and administrative expenses		(468	)		(330	)		(315	)		(297	)		(385	)
Operating income (loss)		(838	)		(100	)		(769	)		(1,146	)		823
Interest expense		(389	)		(453	)		(503	)		(241	)		(201	)
Income tax benefit (expense)		395			172			296			337			(320	)
Net income (loss) from continuing operations		(804	)		(180	)		(813	)		(1,217	)		423
Income (loss) from discontinued operations (3)		899			165			81			(1,136	)		(24	)
Cumulative effect of change in accounting principles		(5	)		—			40			(234	)		2
Net income (loss)	$	90		$	(15	)	$	(692	)	$	(2,587	)	$	401
Net income (loss) applicable to common stockholders		68			(37	)		321			(2,917	)		359
Basic earnings (loss) per share from continuing operations	$	(2.13	)	$	(0.53	)	$	0.53		$	(4.23	)	$	1.17
Basic net income (loss) per share		0.18			(0.10	)		0.86			(7.97	)		1.10
Diluted earnings (loss) per share from continuing operations	$	(2.13	)	$	(0.53	)	$	0.50		$	(4.23	)	$	1.12
Diluted net income (loss) per share		0.18			(0.10	)		0.78			(7.97	)		1.06
Shares outstanding for basic EPS calculation		387			378			374			366			326
Shares outstanding for diluted EPS calculation		513			504			423			370			340
Cash dividends per common share	$	—		$	—		$	—		$	0.15		$	0.30
Cash Flow Data:
Net cash provided by (used in) operating activities	$	(30	)	$	5		$	876		$	(25	)	$	550
Net cash provided by (used in) investing activities		1,824			262			(266	)		677			(3,828	)
Net cash provided by (used in) financing activities		(873	)		(115	)		(900	)		(44	)		3,450
Cash dividends or distributions to partners, net		(22	)		(22	)		—			(55	)		(98	)
Capital expenditures, acquisitions and investments		(315	)		(314	)		(338	)		(981	)		(4,687	)

Index to Financial Statements


	December 31,
	2005		2004		2003		2002		2001
	(restated)		(restated)		(restated)		(restated)		(restated)
	(in millions)
Balance Sheet Data (2):
Current assets	$	3,706	$	2,728	$	3,074	$	7,574	$	8,944
Current liabilities		2,116		1,802		2,450		6,748		8,538
Property and equipment, net		5,323		6,130		8,178		8,458		9,269
Total assets		10,126		9,843		12,801		20,020		25,074
Long-term debt (excluding current portion)		4,228		4,332		5,893		5,454		5,016
Notes payable and current portion of long-term debt		71		34		331		861		458
Serial preferred securities of a subsidiary		—		—		11		11		46
Subordinated debentures		—		—		—		200		200
Series B Preferred Stock (4)		—		—		—		1,212		882
Series C convertible preferred stock		400		400		400		—		—
Minority interest (5)		—		106		121		146		1,040
Capital leases not already included in long-term debt		—		—		—		15		29
Total equity		2,140		1,956		1,975		2,256		4,956

(1)

The following 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:

•

Sithe Energies—February 1, 2005;

•

Northern Natural—February 1, 2002;

•

BGSL—December 1, 2001 and

•

iaxis—March 1, 2001.

(2)

The Sithe Energies, Northern Natural, BGSL and iaxis 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 for respective effective dates.

(3)	Discontinued operations includes 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); and

•

DMSLP (sold fourth quarter 2005).

(4)

The 2002 amount equals the $1.5 billion in proceeds related to the Series B Preferred Stock less the $660 million implied dividend recognized in connection with the beneficial conversion option plus $372 million in accretion of the implied dividend through December 31, 2002. The 2001 amount equals the $1.5 billion in proceeds less the $660 million implied dividend plus $42 million in accretion of the implied dividend through December 31, 2001. Please read Note 13—Related Party Transactions—Series B Preferred Stock beginning on page F-47 for further discussion.

(5)

The 2001 amounts include amounts relating to the Black Thunder Secured Financing. This financing involved our obligation to purchase the interest held by a third party on or before June 2005 which was recorded as an $850 million minority interest liability. We repaid the balance owed under this financing in August 2003.

Index to Financial Statements

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.

PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS AMENDMENT NO. 1, INCLUDING THE FINANCIAL STATEMENTS AND THE NOTES THERETO, DOES NOT REFLECT EVENTS OCCURRING AFTER THE DATE OF THE ORIGINAL FILING, WITH THE EXCEPTION OF THE ITEM DISCUSSED IN THE RESTATEMENT NOTE BEGINNING ON PAGE F-10. SUCH EVENTS INCLUDE, AMONG OTHERS, THE EVENTS DESCRIBED IN OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO. FOR A DESCRIPTION OF THESE EVENTS, PLEASE READ OUR EXCHANGE ACT REPORTS FILED SINCE MARCH 15, 2006.

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; (2) the Northeast segment; and (3) the South segment. We also separately report the results of our CRM business, which primarily consists of Kendall, our remaining power tolling arrangement (excluding the Sithe toll which is now in GEN-NE and is an intercompany agreement) as well as our physical gas supply contracts, gas transportation contracts and remaining 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, interest and depreciation and amortization. As described below, our natural gas liquids business, which was conducted through DMSLP and its subsidiaries, was sold to 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.

Following is a brief discussion of each of our power generation and customer risk management businesses, including a list of key factors that have affected, and are expected to continue to affect, their respective earnings and cash flows. We also present a brief discussion of our corporate-level expenses and our discontinued business segments. This “Overview” section concludes with a discussion of our 2005 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 energy, capacity and ancillary services. Primary factors impacting our earnings and cash flows in the 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, among other things, weather and general economic conditions. Power supplies similarly vary by region and are impacted significantly by available generating capacity, transmission capacity and federal and state regulation. We also are 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,” and its impact on our cost to generate electricity. However, we believe that our significant coal-fired generating facilities partially mitigate our sensitivity to changes in the spark spread, in that our cost of coal particularly in the Midwest, is relatively stable, and position us for potential increases in earnings and cash flows in an environment where both power and gas prices increase.

Index to Financial Statements

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

•

our ability to control our 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 through in-market availability, reliable run-time and safe, efficient operations.

Please read Item 1A. Risk Factors beginning on page 23 of our Original Filing for additional factors that could impact our future operating results, financial condition and cash flows.

In addition to these overarching factors, other factors have impacted, and are expected to continue to impact, earnings and cash flows for our three reportable segments within the power generation business.

Power Generation—Midwest Segment. Our assets in the Midwest include (1) our primarily coal-fired fleet and (2) our gas-fired fleet. Although the primary factor impacting earnings and cash flows in GEN-MW, especially the coal-fired fleet, is market power prices, the following specific factors also impact or could impact the performance of this reportable segment:

•

Ongoing regulatory developments with respect to how major utilities in Illinois procure power beginning in 2007 to serve their customers will impact how we sell our generation.

•

Our ability to maintain sufficient coal inventories, including 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 load.

•

Potential for the State of Illinois to pursue legislation for a limitation of mercury emissions that is more stringent than federal guidelines could impose additional costs on our facilities.

•

As a result of the Baldwin consent decree, cash flows in this segment will be committed to significant capital expenditures over the next few years.

•

In our gas-fired fleet, earnings and cash flows are primarily weather driven. A warm summer or cold winter increases the demand for electricity, which in turn increases the 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 region include gas, fuel oil and coal-fired facilities. The following specific factors also impact or could impact the performance of this reportable segment:

•

The relationship between prices for power and natural gas, commonly referred to as the “spark spread,” and its effect on the cost of generating electricity, impacts our gas-fired facilities in this segment.

•

The relationship between prices for power and fuel oil, and its effect on our cost to generate electricity, impacts our Roseton facility.

•

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.

•

A state-driven program aimed at capping carbon dioxide emissions that is more stringent than federal guidelines could impact future results.

•

The outcome of administrative proceedings and litigation specific to water discharge issues could materially impact operating costs at two of our New York facilities. For further discussion of these matters, please see Note 18—Regulatory Issues—Roseton State Pollutant Discharge Elimination System Permit beginning on page F-67 and Note 18—Regulatory Issues—Danskammer State Pollutant Discharge Elimination System Permit beginning on page F-68, respectively.

Index to Financial Statements

Power Generation—South Segment. Assets in our South region are all gas-fired facilities. Our ERCOT facility is a base-load facility, and our other wholly-owned assets in the segment are peaking units. In December 2005, we announced our agreement to sell our remaining ownership interest in West Coast Power, which comprises our most significant equity investment in our South segment. The following specific factors also impact or could impact the performance of this reportable segment:

•

For the peaking units in this reportable segment, earnings and cash flows are primarily weather driven. A warm summer or cold winter increases the demand for electricity, which in turn increases the run time of our peaking plants. Natural gas market prices have remained high throughout 2005, and power prices have generally tracked high gas prices, enabling us to benefit from operation of all of our peaking facilities during the summer months.

•

Our ability to enter into capacity agreements for our peaker 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.

Customer Risk Management

Our CRM segment is comprised largely of the Kendall power tolling arrangement (excluding the Sithe toll which is now in GEN-NE and is an intercompany agreement). In addition, our CRM segment includes physical gas supply contracts, gas transportation contracts and remaining 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 gas, power and emission trading businesses, 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 transactions still require cash proceeds to purchase gas for our customers; however, those cash requirements are partially offset by the proceeds received from financial contracts hedging the supply. Therefore, the profit and loss impact of price movements are mitigated by these offsetting financial positions. Our remaining power trading business, exclusive of our power tolling arrangements, is expected to be substantially exited by the end of 2006. Although these transactions are accounted for on a mark-to-market basis and will continue to impose volatility in our statement of operations as prices change during the year, we currently anticipate that these transactions will be cash flow positive for 2006 on an aggregate basis. Finally, we have forward obligations to deliver SO₂ emission allowances in 2006, 2007, and 2008, and we currently own adequate allowances to satisfy the forward obligations. However, we experience volatility in our statement of operations, as the value of these obligations changes due to changes in underlying emissions prices, and while the allowances are included in inventory on our consolidated balance sheets, only downward changes in value are recognized in our statement of operations.

Other

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

•

interest expense, which increased beginning in 2003 as a result of our refinancing and restructuring activities and will continue to reflect our non-investment grade credit ratings;

•

general and administrative costs, 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 and (ii) potential funding requirements under our pension plans; and

•

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

Index to Financial Statements

In addition, dividends associated with our outstanding preferred stock will continue to affect our earnings available to our common shareholders.

Discontinued Businesses

Natural Gas Liquids. Our natural gas liquids business, which we sold to Targa Resources in October 2005, was comprised of our natural gas gathering and processing, or upstream, 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 segment 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 AmerenIP.

Company Highlights

During 2005, we continued to work to restore credibility and trust in our company, in part through the restructuring and elimination of many liabilities and risks facing us. To that end, we accomplished the following throughout 2005:

•

February 2005—we acquired Sithe Energies. As a result of this acquisition, a significant toll obligation became an intercompany agreement.

•

May 2005—we entered into a comprehensive settlement resolving environmental litigation related to our Baldwin Energy Complex in Illinois.

•

July 2005—the U.S. District Court approved the comprehensive settlement agreement of the parties in our shareholder class action litigation.

•

October 2005—we completed the sale of DMSLP, which comprised substantially all of the operations of our NGL segment, to Targa Resources Inc. and two of its subsidiaries.

•

October 2005—we entered into a Second Amended and Restated Credit Agreement comprised of (i) a $400 million letter of credit component and (ii) a $600 million revolving credit component. On November 1, 2005, the $600 million outstanding principal balance associated with the revolver was paid in full, and on December 16, 2005, we elected to terminate the revolving credit commitment.

•

November 2005—we approved several changes to our executive management team.

•

December 2005—we completed an asset sale offer to purchase at par up to $1.75 billion aggregate principal amount of our Second Priority Senior Secured Floating Rate Notes Due 2008, 9.875% Second Priority Senior Secured Notes Due 2010 and 10.125% Second Priority Senior Secured Notes Due 2013 under the terms of the Indenture governing such notes, redeeming all of the $400,000 in aggregate principal amount outstanding that were validly tendered for redemption by the holders and not withdrawn.

•

December 2005—we entered into an agreement with Quachita Power LLC, a joint venture of GE Energy Financial Services and Cogentrix Energy, Inc., to terminate the Sterlington toll contract. The agreement closed on March 7, 2006.

•

December 2005—we announced a comprehensive restructuring plan in order to better align our corporate cost structure with our single line of business. The plan included position eliminations and process and system changes.

•

December 2005—we entered into two purchase and sale agreements with NRG Energy, Inc. pursuant to which we will purchase NRG’s 50% indirect interest in the Rocky Road facility, and NRG will purchase our 50% indirect interest in WCP (Generation) Holdings LLC. The transactions, which are conditioned upon one another, are expected to close in early 2006.

Index to Financial Statements

Key Objectives. Looking forward, the following objectives will govern how we conduct our business and make key decisions:

•

Further reduce total debt while maintaining a flexible capital structure that provides an opportunity for growth and market recovery;

•

Sustain adequate liquidity to provide a solid financial foundation;

•

Achieve fiscally responsible growth through combinations or acquisitions of assets that are a strategic fit or can create cost synergies with existing assets; and

•

Provide long term return on investment to shareholders.

In the near term, we are focused on deploying the proceeds from the sale of DMSLP in a manner that best aligns with our key objectives. We are considering executing one or more financing transactions in the near term designed to reduce existing debt or preferred stock obligations or replace certain remaining debt obligations with less restrictive obligations. Transactions to redeem outstanding debt or preferred stock may require us to pay a premium over market price. We are also considering other capital-raising activities in the near term, including potential public or private equity issuances the proceeds of which may be used to fund reductions or redemptions of debt or preferred stock obligations. Matters to be considered will include reducing cash interest expense, covenant flexibility, return on investment and maturity profile all to be balanced with maintaining adequate liquidity. We cannot assure you that we will be successful in our efforts to deploy the DMSLP sale proceeds consistent with these objectives.

We further believe that our efficient and scalable operations platform, together with our multi-fuel capabilities and regionally-focused presence, position us to benefit from opportunities that might arise in connection with any growth transactions or industry consolidation activities. To achieve these strategic objectives, we expect to continue to pursue opportunities that may develop and expand our existing facilities, achieve operating efficiencies or provide opportunistic expansion within our core markets.

However, our desire or ability to pursue any such opportunities is subject to a number of factors beyond our control. As such, we cannot guarantee that any such opportunities will be available to us, nor can we predict with any degree of certainty the impact of any such opportunities on our financial condition or results of operations.

Please read Item 1A. Risk Factors beginning on page 23 of our Original Filing 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, legal settlements 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, asset sale proceeds and proceeds from capital market transactions, to the extent that we engage in these activities prospectively.

Debt Obligations

During 2005, we continued our efforts to reduce our outstanding debt and extend our maturity profile, evidenced by the following transactions:

•

$18 million repayment of 8.125% senior notes that matured in March 2005;

Index to Financial Statements

•

$34 million payment related to our Independence Senior Notes due 2007;

•

$597 million repayment of amount outstanding on our term loan and repayment of accrued interest associated with the former credit facility, repaid with $600 million borrowed under the revolving credit component of the Amended and Restated Credit Facility;

•

$189 million repayment of generation facility borrowings on October 31, 2005; and

•

$600 million repayment of amount due under the revolving credit component of the Amended and Restated Credit Facility in November 2005.

Following such repayments, our debt maturity profile as of December 31, 2005 includes $71 million in 2006, $40 million in 2007, $269 million in 2008, $57 million in 2009, $688 million in 2010 and approximately $3.2 billion thereafter. Maturities for 2006 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 and Long-term debt on our consolidated balance sheets.

Amended and Restated Credit Facility. On October 31, 2005, we replaced our former $1.3 billion credit facility with a second amended and restated credit agreement (the “Amended and Restated Credit Facility”), comprised of (i) a $400 million letter of credit component maturing in October 2008 and (ii) a $600 million revolving credit component, which matured in December 2005. The Amended and Restated Credit Facility was collateralized with cash as well as other assets that were pledged under the former credit facility, excluding those assets sold in connection with the sale of DMSLP, as we were required to post cash collateral in an amount equal to 103% of outstanding letters of credit and borrowings under the Amended and Restated Credit Facility. We earned interest income on the cash on deposit in the cash collateral account.

A letter of credit fee was payable on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 0.50% of the undrawn amount. We also incurred additional fees for issuing letters of credit. Amounts drawn on letters of credit issued pursuant to the facility, as well as borrowings under the revolving credit component of the facility, bore interest at a base rate plus 0.50% per annum. An unused commitment fee of 0.10% was payable on the unused portion of the Amended and Restated Credit Facility.

On October 31, 2005, we borrowed $600 million under the revolving credit component of the Amended and Restated Credit Facility to repay the term loan and accrued interest associated with the former credit facility. The $600 million outstanding principal balance of the revolving credit component was paid in full on November 1, 2005 without a corresponding reduction in revolving credit commitments. On December 16, 2005, we elected to terminate the revolving credit commitment under the Amended and Restated Credit Facility.

Senior Secured Credit Facility. On March 6, 2006, we entered into a third amended and restated credit agreement (the “Senior Secured Credit Facility”) with Citicorp USA, Inc. and JPMorgan Chase Bank, N.A., as co-administrative agents, JP Morgan Chase Bank, N.A., as collateral agent, Citigroup Global Markets Inc. and JP Morgan Securities Inc., as joint lead arrangers, and the other financial institutions parties thereto as lenders. The Senior Secured Credit Facility replaces our former cash-collateralized Amended and Restated Credit Facility with a $400 million revolving credit facility, thereby permitting the return to DHI of $335 million plus accrued interest in cash collateral securing the former Amended and Restated Credit Facility. The Senior Secured Credit Facility is secured by substantially all of the assets of DHI, as borrower, and certain of its subsidiaries, as subsidiary guarantors, and certain of the assets of Dynegy, as parent guarantor. Letters of credit issued under the former Amended and Restated Credit Facility will be continued under the Senior Secured Credit Facility.

The revolving credit facility matures March 6, 2009. Borrowings under the revolving credit facility bear interest, at DHI’s option, at either the base rate, which is calculated as the higher of Citibank’s publicly announced base rate and the federal funds rate in effect from time to time plus 0.50%, or the Eurodollar rate, in each case, plus an applicable margin. The applicable margin is 1% per annum for base rate loans and 2% percent per annum for Eurodollar loans. An unused commitment fee of 0.50% is payable on the unused portion of the revolving credit facility.

Index to Financial Statements

The Senior Secured Credit Facility contains mandatory prepayment provisions associated with specified asset sales and dispositions (including as a result of casualty or condemnation) and the receipt of proceeds by DHI and certain of its subsidiaries of any permitted additional non-recourse indebtedness. Commencing in 2008 with respect to the fiscal year ending December 31, 2007, each year DHI will be required to apply toward the prepayment of the loans and the permanent reduction of the commitments under the revolving credit facility (or to posting cash collateral in lieu thereof), a portion of its excess cash flow as calculated under the Senior Secured Credit Facility for the prior fiscal year. This portion will be 50% initially and will fall to 25% when and if DHI’s leverage ratio is less than or equal to 3.50 to 1.00.

The Senior Secured Credit Facility contains affirmative covenants and negative covenants and events of default. Subject to certain exceptions, DHI and its subsidiaries are subject to restrictions on incurring additional indebtedness, limitations on capital expenditures and limitations on dividends and other payments in respect of capital stock. The Senior Secured Credit Facility also contains certain financial covenants, including a minimum cash equivalents covenant that requires DHI and certain of its subsidiaries to maintain at all times cash equivalents in an aggregate principal amount of no less than $1 billion and a leverage ratio of secured debt to adjusted EBITDA of no greater than 9.0:1 through December 31, 2006, no greater than 7.5:1 during 2007, and no greater than 7.0:1 during 2008 and thereafter.

We have incurred significant debt service obligations in the course of extending our debt maturities. We also are subject to covenants in the related transaction agreements that are substantially more restrictive than those typically found in financing agreements of borrowers with investment grade credit ratings, including covenants limiting our ability to incur additional debt, distribute funds within our corporate structure and sell certain assets. We are currently in compliance with these restrictive covenants, but our future financial condition and results of operations could be materially adversely affected by our ability to comply with these restrictive covenants in the future.

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, 2005 and 2004:


	December 31, 2005			December 31, 2004
	(in millions)
First Secured Obligations
Dynegy Holdings Inc.	$	785		$	1,551
Sithe Energies (1)		885			—

Total First Secured Obligations		1,670			1,551
Second Secured Obligations		1,750			1,750
Unsecured Obligations		1,786			1,831

Subtotal		5,206			5,132
Preferred Obligations		400			400

Total Obligations	$	5,606		$	5,532

Less: DNE Lease Financing (2)		(785	)		(771	)
Less: Preferred Obligations		(400	)		(400	)
Other (3)		(122	)		5

Total Notes Payable and Long-term Debt (4)	$	4,299		$	4,366

(1)	Please read Note 3—Acquisition—Sithe Energies beginning on page F-23 for further discussion.

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

(3)	Consists of net discounts on debt of $122 million and net premiums on debt of $5 million at December 31, 2005 and 2004, respectively.

(4)	Does not include letters of credit.

Index to Financial Statements

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 March 7, 2006, December 31, 2005 and December 31, 2004:


	March 7, 2006		December 31, 2005		December 31, 2004
	(in millions)
By Business:
Generation business	$	185	$	280	$	192
Customer risk management business		76		91		94
Natural gas liquids business		—		—		167
Other		8		10		17

Total	$	269	$	381	$	470

By Type:
Cash (1)	$	81	$	122	$	376
Letters of Credit		188		259		94

Total	$	269	$	381	$	470

(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 decrease in collateral postings from December 31, 2005 to March 7, 2006 is primarily due to a return of collateral postings in our generation business. This decrease is primarily a result of decreases in commodity prices since the end of 2005. The decrease in collateral postings from December 31, 2004 to December 31, 2005 is primarily due to a return of collateral postings related to the natural gas liquids business as a result of the sale of DMSLP, offset by an $88 million increase in postings in our generation business. This increase in our generation business is primarily the result of increases in commodity prices and an increase in the volume of fuel purchased as we no longer purchase gas from DMSLP. In addition, approximately $40 million of the increase is due to cash collateral posted by Dynegy on behalf of West Coast Power. A significant majority of this amount is offset by cash collateral received from West Coast Power. This amount will be eliminated upon the sale of our 50% interest in West Coast Power, currently anticipated to occur in early 2006. The collateral posted in support of our customer risk management business on December 31, 2005 was $3 million less than the amount posted on December 31, 2004. During 2005 the collateral posted on behalf of our customer risk management business decreased primarily due to the expiration of the Gregory tolling agreement and the rolloff of NYMEX positions, which was offset by an increase in volumes of fuel purchased. Finally, Other collateral postings decreased primarily as a result of a refund of collateral related to Illinois Power subsequent to its sale in September 2004.

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. Considering our credit ratings, the sale of DMSLP and current commodity price estimates, specifically as prices relate to fuel purchases and power hedging activity, we estimate that collateral requirements will be approximately $300 million at year-end 2006. We believe that we have sufficient capital resources to satisfy counterparties’ collateral demands, including those for which no collateral is currently posted, for at least the next twelve months. Over the longer term, we expect to achieve incremental collateral reductions associated with the completion of our exit from the customer risk management business.

Index to Financial Statements

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, 2005. Cash obligations reflected are not discounted and do not include related interest, accretion or dividends.


	Payments Due by Period
	Total		2006		2007		2008		2009		2010		Thereafter
Long-Term Debt (including Current Portion)	$	4,299	$	71	$	40	$	269	$	57	$	688	$	3,174
Redeemable Preferred Securities		400		—		—		—		—		—		400
Operating Leases		1,546		97		144		162		160		114		869
Capacity Payments		1,509		136		138		140		142		145		808
Conditional Purchase Obligations		123		12		11		13		11		12		64
Pension Funding Obligations		70		17		12		18		14		9		—
Other Obligations		86		12		16		16		16		17		9

Total Contractual Obligations	$	8,033	$	345	$	361	$	618	$	400	$	985	$	5,324

Long-Term Debt (including Current Portion). Total amounts of Long-Term Debt (including Current Portion) are included in the December 31, 2005 Consolidated Balance Sheet. For additional explanation, please read Note 12—Debt beginning on page F-43.

Additionally, we have entered into various joint ventures principally to share risk or optimize existing commercial relationships. These joint ventures maintain independent capital structures and, where necessary, have financed their operations on a non-recourse basis to us. Please read Note 10—Unconsolidated Investments beginning on page F-36 for further discussion of these joint ventures.

Redeemable Preferred Securities. Total amounts of Redeemable Preferred Securities are included in the December 31, 2005 Consolidated Balance Sheet. For additional explanation, please read Note 15—Redeemable Preferred Securities beginning on page
F-55.

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 14. 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 $13 million each year for the years 2006 through 2008, and approximately $66 million through lease expiration. The charter party rates payable under the two charter party agreements float in accordance with market based rates for similar shipping services. The $13 million and $66 million numbers 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 are currently in negotiations with the owners of the VLGCs and their lenders to obtain a novation and release of our operating

Index to Financial Statements

subsidiary from the two charter party agreements and partial releases of our parent guarantees. Until such time as the novations and partial releases are granted, 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.

Capacity Payments. Capacity payments include future payments aggregating $1.2 billion under the Sterlington and Kendall power tolling arrangements, as further described in Item 1. Business—Segment Discussion—Customer Risk Management Segment beginning on page 14 of our Original Filing. We terminated the Sterlington long-term wholesale power tolling contract with Quachita Power LLC effective March 7, 2006. Accordingly, the capacity payments of approximately $751 million associated with this agreement will be eliminated. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Sterlington Contract Termination beginning on page F-25 for further discussion.

In November 2004, we entered into a “back-to-back” power purchase agreement under which a subsidiary of Constellation Energy receives our rights to capacity and energy under the Kendall tolling arrangement for a four year term expiring effectively in November 2008. Although we are still obligated under the Kendall toll, as of December 31, 2005, we will receive approximately $122 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 beginning on page F-27 below for further discussion.

In addition, capacity payments include fixed obligations associated with transmission, transportation and storage arrangements totaling approximately $302 million.

Conditional Purchase Obligations. Amounts relate to our co-sourcing agreement with Accenture LLP for employee and infrastructure outsourcing. The co-sourcing agreement previously contained a contract termination fee, which ranges from $5 million if terminated in the first quarter of 2006, declining to $2 million if terminated during 2013, and allows for renegotiation, or “partial termination”, if our purchasing levels fall below minimum levels. As of December 31, 2005, the termination fee was $5 million. In the fourth quarter, as a result of our sale of DMSLP to Targa, we determined our purchasing levels would no longer meet the minimum levels set forth in the co-sourcing agreement and initiated negotiations with Accenture to partially terminate, or amend, the co-sourcing agreement. During the fourth quarter 2005, we recorded a $3 million pre-tax charge to reflect our best estimate of the cost associated with the partial termination of the co-sourcing agreement. The charge is reflected as a reduction in the gain on sale of DMSLP included in income from discontinued operations on our consolidated statements of operations. We recently amended this agreement to reduce our annual rate and to extend the term through October 2015. We agreed to pay $3 million to Accenture in early 2006 in connection with the execution of the amended 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 2006 ($17 million), 2007 ($12 million) and 2008 ($18 million). Although we expect to incur significant funding obligations subsequent to 2008, 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 $66 million as of December 31, 2005. 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 $20 million as of December 31, 2005. Please read Note 3—Acquisition—Sithe Energies beginning on page F-23 for more information on this agreement.

Index to Financial Statements

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 $17 million over the ten year term of the lease.

Contingent Financial Obligations

The following table provides a summary of our contingent financial obligations as of December 31, 2005 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)	$	259	$	254	$	5	$	—	$	—
Surety Bonds (2)(3)		34		34		—		—		—
Guarantees (4)		4		—		4		—		—

Total Financial Commitments	$	297	$	288	$	9	$	—	$	—

(1)	Amounts include outstanding letters of credit.

(2)	Surety bonds are generally on a rolling 12-month basis.

(3)	$31 million of the surety bonds were supported by collateral.

(4)

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. 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. For further information, please see Note 17—Commitments and Contingencies—Other Commitments and Contingencies—Guarantees and Indemnifications.

Off-Balance Sheet Arrangements

DNE Leveraged Lease. We established our presence in the Northeast region by acquiring the DNE power generating facilities in January 2001 for $950 million.

In May 2001, we entered into an asset-backed sale-leaseback transaction relating to these facilities to provide us with long-term financing for our acquisition. 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 these 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., who 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.

Index to Financial Statements

As of December 31, 2005, future lease payments are $60 million for 2006, $108 million for 2007, $144 million for 2008, $141 million for 2009, $95 million for 2010 and $112 million for 2011, with $712 million in the aggregate due from 2012 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, 2005, the present value (discounted at 10%) of future lease payments was $785 million.

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


	2005		2004		2003
	(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, 2005, 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-40.

Capital Expenditures

We continue to tightly manage costs and capital expenditures. We had approximately $195 million in capital expenditures during 2005. Our 2005 capital spending by reportable segment was as follows (in millions):


GEN-MW	$	113
GEN-NE		21
GEN-SO		9
NGL		45
Other		7

Total	$	195

Capital spending in our GEN-MW segment primarily consisted of maintenance capital projects, as well as approximately $33 million spent on development capital. Development capital spending primarily related to the conversion of our Havana and Vermilion facilities to PRB coal. Capital spending in our GEN-NE and GEN-SO segments primarily consisted of maintenance and environmental projects. Capital spending in our NGL segment primarily related to maintenance capital projects and wellconnects, as well as approximately $11 million in development capital.

Index to Financial Statements

We expect capital expenditures for 2006 to approximate $189 million. 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. Estimated funds budgeted for the aforementioned items by reportable segment in 2006 are as follows (in millions):


GEN-MW	$	112
GEN-NE		47
GEN-SO		25
Other		5

Total	$	189

Our capital expenditures in 2006 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-43 for further discussion of these limitations. Our long term capital expenditures in the GEN-MW segment will also be significantly impacted by the Baldwin 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 $611 million through 2013.

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-57, which is incorporated herein by reference, for a discussion of our commitments and contingencies.

Dividends on Preferred and 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. We do not foresee a declaration of dividends on our common stock in the near term, particularly given our financial condition and the dividend restrictions contained in our financing agreements. Specifically, we have agreed not to pay any dividends on our common stock under the terms of the Senior Secured Credit Facility. We have, however, continued to make the required dividend payments on our outstanding trust preferred securities.

The Series B Preferred Stock issued to Chevron in November 2001 had no dividend requirement. Because of Chevron’s discounted conversion option, however, we accreted an implied preferred stock dividend over the redemption period, as required by GAAP. Please read Note 13—Related Party Transactions—Series B Preferred Stock beginning on page F-47 for further discussion of this non-cash implied dividend and the Series B Exchange. In conjunction with the Series B Exchange, we recognized a gain of approximately $1.2 billion as a preferred stock dividend during 2003.

We accrue dividends on our Series C preferred stock at a rate of 5.5% per annum. We accrued and made dividend payments on the Series C preferred stock during the year ended December 31, 2005 totaling approximately $22 million. Dividends are payable on the Series C preferred stock in February and August of each year, but we may defer payments for up to 10 consecutive semi-annual periods. Please read Note 15—Redeemable Preferred Securities beginning on page F-55 for further discussion.

Index to Financial Statements

We declared and paid dividends of $11 million in February 2006. Unless we have sufficient liquidity at the parent level, we may be required to defer payment of dividends on the Series C preferred stock beginning in August 2006.

Please read—Company Highlights—Key Objectives beginning on page 8 for discussion of potential near-term liability management activities, which may include reduction or redemption of debt or preferred stock obligations.

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 March 7, 2006, December 31, 2005 and December 31, 2004:


	March 7, 2006			December 31, 2005			December 31, 2004
	(in millions)
Total revolver capacity	$	400	(4)	$	—		$	700
Total additional letter of credit capacity		—			325	(1)		—
Outstanding letters of credit under credit facility		(188	)		(254	)		(94	)

Unused credit facility capacity		212			71			606
Cash		1,528	(2)		1,549	(2)		628	(2)(3)

Total available liquidity	$	1,740		$	1,620		$	1,234

(1)

On October 31, 2005, we amended and restated the credit facility to consist of (i) a $400 million letter of credit component and (ii) a $600 million revolving credit component. On December 16, 2005, we elected to terminate the revolving credit commitment. Please read Note 12—Debt—Amended and Restated Credit Facility beginning on page F-44 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 March 7, 2006, December 31, 2005 and December 31, 2004 amounts include approximately $3 million, $3 million and $47 million, respectively, of cash that remains in the U.K. only for the year ended December 31, 2005 and both Canada and the U.K. for the year ended December 31, 2004 that is associated primarily with contingent liabilities relating to our former Canadian and U.K. marketing and trading operations.

(3)	The December 31, 2004 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-28.

(4)	On March 6, 2006, we amended and restated the credit facility. Please see Note 23—Subsequent Events beginning on page F-85.

Cash Flows from Operations. We had operating cash outflows of $30 million for the year ended December 31, 2005. This consisted of $472 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, partially offset by decreases in working capital due to increased accounts receivable. Additionally, this included $288 million in operating cash flows from our discontinued natural gas liquids business. The cash flows from these businesses were offset by $790 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.

For 2006, our estimate of operating cash outflows totals $210 to $100 million. This estimate, which is based on quoted forward commodity prices curves as of February 7, 2006 and is subject to change based on a number

Index to Financial Statements

of factors, many of which are beyond our control, reflects $530 to $630 million in estimated operating cash flows from our generation business, offset by estimated cash outflows of $380 million from our customer risk management business and $360 to $350 million in corporate-level expenses, including $410 million of interest.

On October 31, 2005, cash interest expense associated with the term loan and the generation facility debt were eliminated, as these instruments were repaid in full. However, until the remaining cash proceeds from the sale of DMSLP are re-invested or utilized in a liability management program, as more fully described in Note 12—Debt—DMSLP, the interest income from the cash proceeds will be more than offset by the reduction in operating cash flows from the NGL business and may continue to be more than offset depending on the ultimate disposition of the cash.

Over the longer term, our operating cash flows also will be impacted by, among other things, our ability to manage tightly our operating costs, including costs for fuel and maintenance. Our ability to achieve fuel-related and other 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—2006 Outlook” for further discussion.

Cash on Hand. At March 7, 2006 and December 31, 2005, we had cash on hand of $1,528 million and $1,549 million, respectively, as compared to $628 million at the end of 2004. This increase in cash on hand at March 7, 2006 and December 31, 2005 as compared to the end of 2004 is primarily attributable to the sale of DMSLP and is offset by cash used for debt repayments, in the Sithe acquisition, shareholder litigation settlement and capital expenditures.

Revolver Capacity. On October 31, 2005, we entered into an Amended and Restated Credit Agreement comprised of (1) a $400 million letter of credit component and (2) a $600 million revolving credit component. On December 16, 2005, we elected to terminate the revolving credit commitment. We were required to post cash collateral in an amount equal to 103% of outstanding letters of credit. Therefore, our capacity to issue letters under the Amended and Restated Credit Facility was dependent upon and limited by the amount of cash collateral on deposit. On March 6, 2006, we entered into the Senior Secured Credit Facility replacing the former Amended and Restated Credit Facility with a $400 million revolving credit facility, thereby providing the return to DHI of $335 million plus accrued interest in cash collateral securing the former Amended and Restated Credit Facility. As of March 7, 2006, $188 million in letters of credit are outstanding but undrawn, and we have no revolving loan amounts drawn under the Senior Secured Credit Facility. Please read Note 12—Debt—Amended and Restated Credit Facility beginning on page F-44 for further discussion of our amended credit facility.

External Liquidity Sources

Over the last twelve months, our primary external liquidity source has been proceeds from asset sales. Looking forward, we expect our primary external liquidity sources to be proceeds from asset sales and other types of capital-raising transactions, including public or private equity issuances.

Asset Sale Proceeds. As further discussed in Note 4—Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Natural Gas Liquids beginning on page F-28, we sold DMSLP to Targa Resources Inc. on October 31, 2005. The terms of our former $1.3 billion credit facility and the SPN indenture and security agreements govern the use of the proceeds from this sale.

Pursuant to the SPN Indenture, in December 2005, we completed an asset sale offer to purchase at par up to $1.75 billion aggregate principal amount of our SPNs from the holders thereof at a price equal to 100% of the principal amount plus accrued and unpaid interest. We accepted for purchase and redeemed all of the $400,000 in aggregate principal amount of the notes that were validly tendered and not withdrawn. The funds available for this offer to purchase represented net cash proceeds from the sale of DMSLP. Under the terms of the SPN Indenture, “Excess Proceeds” from the sale of DMSLP were approximately $2.4 billion. After giving effect to the purchase of SPNs pursuant to the asset sale offer, the remaining Excess Proceeds may be used for any purpose not otherwise prohibited by the SPN Indenture.

Index to Financial Statements

Capital-Raising Transactions. As part of our ongoing efforts to develop a capital structure that is more closely aligned with the cash-generating potential of our asset-based business, which is subject to cyclical changes in commodity prices, we are continuing to explore additional capital-raising transactions both in the near- and long-term. The timing of any capital-raising transaction may be impacted by unforeseen events, such as strategic growth opportunities, legal judgments or regulatory requirements, which could require us to pursue additional capital in the near term.

These transactions may include capital markets transactions. Our ability to issue public securities is enhanced by our effective shelf registration statement, under which we have approximately $430 million in remaining availability. This availability was not reduced by the issuance on August 12, 2005 of 17,578,781 shares of Dynegy Class A common stock pursuant to the settlement of the shareholder class action litigation, as such issuance was exempt from registration under the Securities Act of 1933. 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 credit facility. Please read Note 12—Debt—Amended and Restated Credit Facility beginning on page F-44 for further discussion.

Conclusion

During 2005, we acquired Sithe Energies, which resulted in a toll obligation becoming an intercompany agreement. Mid-year, we entered into agreements to settle our Baldwin environmental litigation and our shareholder class action litigation. We completed the sale of DMSLP and aligned our corporate cost structure with our single line of business. Further, we replaced our former credit facility with an Amended and Restated Credit Facility comprised of a $400 million letter of credit component, scheduled to mature in October 2008, and a $600 million revolving credit component, which we paid in full in November and elected to terminate on December 16, 2005. In the fourth quarter, we completed an asset sale offer to purchase at par up to $1.75 billion aggregate principal amount of our SPNs under the terms of the indenture governing such notes as well as announced a new executive management team. We ended the year by entering into separate agreements (i) to terminate the Sterlington toll contract in order to eliminate significant future capacity obligation payments, and (ii) to exchange our ownership interest in West Coast Power for NRG’s ownership interest in Rocky Road.

We have established key objectives that will govern how we conduct our business and make decisions. Thus, looking forward, we are focused on executing strategies to deploy the proceeds from the sale of DMSLP in a manner that best aligns us with our key objectives. We are considering executing one or more financing transactions in the near-term designed to reduce existing debt or preferred stock obligations or replace certain remaining debt obligations with less restrictive obligations. We further believe that our efficient and scalable operations platform, together with our multi-fuel capabilities and regionally-focused presence, position us to benefit from opportunities that might arise in connection with any growth transactions or industry consolidation activities.

Over the longer term and through the anticipated recovery of the U.S. power markets, we expect to maintain sufficient liquidity to satisfy our debt and commercial obligations and provide collateral support through operating cash flows, cash on hand or capacity under the revolving component of our Senior Secured Credit Facility. Further, over the last twelve months, our primary external liquidity source has been proceeds from asset sales. Looking forward, we expect our primary external liquidity sources to be proceeds from asset sales and other types of capital-raising transactions, including potential equity issuances.

Our desire or ability to pursue any of the opportunities mentioned above is subject to a number of factors beyond our control. As such, we cannot guarantee that any such strategic direction(s) will be available to us, nor can we predict with any degree of certainty the impact of any such strategic direction(s) on our financial condition, results of operations or cash flows. Please read Item 1A. Risk Factors beginning on page 23 of our Original Filing for additional factors that could impact our future operating results and financial condition.

Index to Financial Statements

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 2005, 2004 and 2003. At the end of this section, we have included our business outlook for each segment.

As reflected in this report, we have changed our reportable segments. Prior to this report, we reported results for the following segments: GEN, NGL, REG and CRM. Other reported results included corporate overhead and our discontinued business. Following the sale of Illinois Power in September 2004 and DMSLP in October 2005, our current business operations are focused primarily on the power generation sector of the energy industry. Therefore, beginning in the fourth quarter 2005, 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 two remaining power tolling arrangements (excluding the Sithe toll which is now in GEN-NE and is an intercompany agreement) as well as our physical gas supply contracts, gas transportation contracts and remaining 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, interest and depreciation and amortization. As described below, substantially all of our natural gas liquids 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 regulated energy delivery 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.

In our year-end 2005 earnings news release furnished with our Form 8-K filed on March 8, 2006, we reported loss from continuing operations of $(803) million and net income applicable to common shareholders of $88 million for the year ended December 31, 2005. The difference between those amounts and the amounts reported herein resulted from an error related to the income tax benefit from continuing operations and the income tax expense from discontinued operations that was identified subsequent to the furnishing of our year-end 2005 earnings news release. As a result, the amounts reported herein reflect a $1 million decrease to the income tax benefit from continuing operations and a $6 million increase to the income tax expense from discontinued operations. Although diluted earnings per share from continuing operations was not impacted by this error, diluted earnings per share from discontinued operations was reduced from $2.37 to $2.35.

Summary Financial Information. The following tables provide summary financial data regarding our consolidated and segmented results of operations for 2005, 2004 and 2003, respectively. This financial data has been restated to reflect the items described in the Restatement Note beginning on page F-10 to the accompanying Consolidated Financial Statements. The restatement relates to our deferred income tax accounts. Please read the Restatement Note for further discussion.

Year Ended December 31, 2005


	Power Generation
	GEN-MW		GEN-NE		GEN-SO			CRM			REG		Other and Eliminations			Total
	(in millions)															(Restated)
Operating income (loss)	$	194	$	29	$	(21	)	$	(647	)	$	—	$	(393	)	$	(838	)
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																	(1,199	)
Income tax benefit																	395

Loss from continuing operations																	(804	)
Income from discontinued operations, net of taxes																	899
Cumulative effect of change in accounting principle, net of taxes																	(5	)

Net income																$	90

Index to Financial Statements

Year Ended December 31, 2004


	Power Generation
	GEN-MW		GEN-NE		GEN-SO			CRM			REG		Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	194	$	21	$	(52	)	$	(118	)	$	139	$	(284	)	$	(100	)
Earnings from unconsolidated investments		80		—		112			—			—		—			192
Other items, net		—		—		1			(3	)		3		8			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	)

Year Ended December 31, 2003


	Power Generation
	GEN-MW		GEN-NE		GEN-SO			CRM			REG			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	196	$	46	$	(48	)	$	(385	)	$	(327	)	$	(251	)	$	(769	)
Earnings (losses) from unconsolidated investments		15		—		113			(2	)		—			—			126
Other items, net		—		—		4			31			—			2			37
Interest expense																		(503	)

Loss from continuing operations before taxes																		(1,109	)
Income tax benefit																		296

Loss from continuing operations																		(813	)
Income from discontinued operations, net of taxes																		81
Cumulative effect of change in accounting principle, net of taxes																		40

Net loss																	$	(692	)

Index to Financial Statements

The following table provides summary segmented operating statistics for 2005, 2004 and 2003, respectively:


	Year Ended December 31,
	2005		2004		2003
GEN-MW
Million Megawatt Hours Generated—Gross and Net		21.9		22.6		23.7
Average On-Peak Market Power Prices ($/MWh):
Cinergy	$	64	$	43	$	37
Commonwealth Edison (NI Hub)	$	62	$	42	$	37

GEN-NE
Million Megawatt Hours Generated—Gross and Net		8.3		6.0		5.6
Average On-Peak Market Power Prices ($/MWh):
New York—Zone G	$	92	$	62	$	61
New York—Zone A	$	76	$	53	$	51

GEN-SO
Million Megawatt Hours Generated—Gross		6.6		8.5		9.8
Million Megawatt Hours Generated—Net		5.3		6.7		7.9
Average On-Peak Market Power Prices ($/MWh):
Southern	$	71	$	49	$	41
ERCOT	$	80	$	51	$	45
SP-15	$	73	$	55	$	52

Average natural gas price—Henry Hub ($/MMBtu) (1)	$	8.80	$	5.85	$	5.28

Natural Gas Liquids (5)
Gross NGL production (MBbls/d):
Field plants		56.6		57.3		59.6
Straddle plants		23.7		26.6		25.6

Total gross NGL production		80.3		83.9		85.2

Natural gas (residue) sales (Bbtu/d)		185.0		182.8		174.4
Natural gas inlet volumes (MMCFD):
Field plants		518.5		535.6		591.0
Straddle plants		1,030.2		990.0		1,103.1

Total natural gas inlet volumes		1,548.7		1,525.6		1,694.1

Fractionation volumes (MBbls/d)		173.8		202.5		185.3
Natural gas liquids sold (MBbls/d)		257.7		282.5		311.7
Average commodity prices:
Crude oil—WTI ($/Bbl)	$	54.75	$	41.43	$	31.01
Natural gas—Henry Hub ($/MMbtu) (2)	$	7.87	$	6.13	$	5.38
Natural gas liquids ($/Gal)	$	0.87	$	0.71	$	0.55
Fractionation spread ($/MMBtu)—daily	$	1.91	$	2.18	$	0.79

Regulated Energy Delivery (6)
Electric sales in KWh (millions)
Residential		—		4,182		5,309
Commercial		—		3,389		4,413
Industrial		—		3,859		6,123
Transportation of customer-owned electricity		—		2,407		2,382
Other		—		287		374

Total electric sales		—		14,124		18,601

Gas sales in Therms (millions)
Residential		—		214		337
Commercial		—		85		145
Industrial		—		40		70
Transportation of customer-owned gas		—		171		226

Total gas delivered		—		510		778

Cooling degree days—Actual (3)		—		932		980
Cooling degree days—10-year rolling average		—		1,236		1,214
Heating degree days—Actual (4)		—		3,145		5,256
Heating degree days—10-year rolling average		—		3,190		4,930

Index to Financial Statements

(1)	Calculated as the average of the daily gas prices for the period.

(2)	Calculated as the average of the first of the month prices for the period.

(3)	A Cooling Degree Day (CDD) represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in our region. The CDDs for a period of time are computed by adding the CDDs for each day during the period.

(4)	A Heating Degree Day (HDD) represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in our region. The HDDs for a period of time are computed by adding the HDDs for each day during the period.

(5)	Operating statistics for NGL for the year ended December 31, 2005 only include statistics through October 31, 2005, the date of the sale of DMSLP to Targa.

(6)	Operating statistics for REG for the year ended December 31, 2004 only include statistics through September 30, 2004, the date of the sale of Illinois Power to Ameren.

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, 2005
	Power Generation
	GEN-MW			GEN-NE		GEN-SO			CRM			NGL		REG		Other			Total
	(in millions)															(Restated)			(Restated)
Discontinued operations (1)	$	—		$	—	$	—		$	6		$	1,250	$	—	$	—		$	1,256
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		—			—		—			—			—		—		86			86

Total	$	(29	)	$	—	$	(27	)	$	(565	)	$	1,250	$	—	$	(174	)	$	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			NGL		REG			Other			Total
	(in millions)
Discontinued operations (1)	$	—		$	—	$	—		$	19		$	254	$	—		$	3		$	276
Kendall toll restructuring		—			—		—			(115	)		—		—			—			(115	)
Legal and settlement charges		(9	)		—		2			(13	)		—		(1	)		(92	)		(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	)	$	254	$	(113	)	$	(79	)	$	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.

Index to Financial Statements


	Year Ended December 31, 2003
	Power Generation
	GEN-MW			GEN-NE		GEN-SO			CRM			NGL		REG			Other			Total
	(in millions)
Illinois Power goodwill impairment	$	—		$	—	$	—		$	—		$	—	$	(311	)	$	—		$	(311	)
Illinois Power asset impairment		—			—		—			—			—		(218	)		—			(218	)
Southern Power tolling settlement		—			—		—			(133	)		—		—			—			(133	)
Sithe power tolling contract		—			—		—			(121	)		—		—			—			(121	)
Legal charges		—			—		—			—			—		—			(50	)		(50	)
Batesville tolling settlement		—			—		—			(34	)		—		—			—			(34	)
Kroger settlement		—			—		—			(30	)		—		—			—			(30	)
Impairment of generation investments	$	(5	)	$	—		(21	)		—			—		—			—			(26	)
Acceleration of financing costs		—			—		—			—			—		—			(24	)		(24	)
West Coast Power goodwill impairment		—			—		(20	)		—			—		—			—			(20	)
Discontinued operations (1)		—			—		—			(30	)		148		(3	)		7			122
Taxes		—			—		(1	)		—			—		—			34			33
Gain on sale of Hackberry LNG (1)		—			—		—			2			—		—			—			2
Cumulative effect of change in accounting principles		45			11		(32	)		43			—		(3	)		—			64

Total	$	40		$	11	$	(74	)	$	(303	)	$	148	$	(535	)	$	(33	)	$	(746	)

(1)	Discontinued operations for NGL includes pre-tax gains on the sale of Hackberry LNG totaling $25 million and a $12 million impairment of an equity investment.

Year Ended 2005 Compared to Year Ended 2004

Operating Loss

Operating loss was $838 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/ComEd 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 output 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 IP 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. Please read Item 1. Business—Segment Discussion—Power Generation—Midwest Segment beginning on page 7 of our Original Filing for a discussion of the contractual terms of these agreements. 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.

Index to Financial Statements

Results for our gas-fired peaking facilities in GEN-MW were 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 gas-fired facilities produced in 2004. However, our 2005 results also include a lower of cost or market 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 Baldwin 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 gas-fired facilities were offset by a $29 million charge associated with the impairment of a gas turbine not currently in use, 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—Acquisition—Sithe Energies beginning on page F-23 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 $21 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 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 $5 million in 2004 to earnings of $4 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 $25 million in 2004 to $23 million for 2005.

CRM. Operating loss for the CRM segment was $647 million for 2005, compared to operating loss of $118 million in 2004.

Index to Financial Statements

Results for 2005 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 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.

•

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

•

$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.

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; and

•

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

This segment’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 gas contracts which had previously been accounted for on an accrual basis.

REG. Operating income for the REG segment was $139 million in 2004. The 2004 period includes a $58 million charge related to the sale of Illinois Power and a $54 million charge for the impairment of assets associated with this segment.

Other. Other operating loss was $393 million in 2005, compared to a loss of $284 million in 2004. Results for 2005 include a $236 million charge associated with the recent 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

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.

Index to Financial Statements

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 own 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 pending 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 pending 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 and the 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 $395 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 and state audits and settlements and other items. Excluding these items from the 2005 and 2004 calculations would

Index to Financial Statements

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-49 for further discussion of our income taxes.

Discontinued Operations

Income From Discontinued Operations Before Taxes. Discontinued operations include our global liquids business and DMSLP in our NGL segment, our U.K. CRM business and U.K. natural gas storage assets in the 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


	U.K. CRM		DGC		NGL			Other		Total
	(in millions)
Operating income included in income from discontinued operations	$	—	$	—	$	1,320		$	—	$	1,320
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											1,256
Income tax expense											(357	)

Income from discontinued operations										$	899

Year Ended December 31, 2004


	U.K. CRM		DGC		NGL			Other		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-28, on October 31, 2005, we completed the sale of DMSLP. As a result of the sale, and as required by Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, 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 $1,256 million ($899 million after-tax) included $1,250 million in pre-tax income attributable to NGL. In 2004, pre-tax income from discontinued operations of

Index to Financial Statements

$276 million ($165 million after-tax) included $254 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. 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 gas treating plant and gathering system due to rapidly depleting reserves associated with that facility.

In accordance with EITF Issue 87-24, “Allocation of Interest to Discontinued Operations,” 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 $357 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 related to our capital loss carryforward 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-28. 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—Accounting Policies—Asset Retirement Obligations beginning on page F-15.

Year Ended 2004 Compared to Year Ended 2003

Operating Loss

Operating loss was $100 million for the year ended December 31, 2004, compared to $769 million for the year ended December 31, 2003.

Power Generation—Midwest Segment. Operating income for GEN-MW, where we produced approximately 60% of our generated volumes, was $194 million for the year ended December 31, 2004, compared to $196 million for the year ended December 31, 2003. Increased prices contributed $23 million for 2004 compared to 2003. Additionally, we experienced a $28 million reduction in coal transportation costs in GEN-MW, resulting from a transportation contract which took effect at the beginning of 2004. However, improved pricing was partially offset by an increase in operating expenses for GEN-MW of approximately $12 million, resulting from the timing of maintenance expenditures, as well as increases in labor costs. Additionally, we reported $17 million less capacity revenue in 2004 as compared with 2003. Volumes were down slightly, from 21.1 million MWh for 2003 to 20.7 million MWh for 2004. This decrease was largely due to reduced production at our Havana facility, resulting from our management of fuel inventories in anticipation of our switch to PRB coal. Our 2004 results include $16 million of mark-to-market losses, compared with $3 million of losses in 2003. Results from our gas-fired peaking facilities decreased from $2 million in 2003 to a loss of $4 million in 2004. Additionally, results were affected by an $8 million increase in depreciation expense, resulting from the completion of our Rolling Hills generation facility, as well as other capital projects placed into service in 2003. General and administrative expense increased slightly, from $37 million in 2003 to $38 million in 2004.

Index to Financial Statements

Power Generation—Northeast Segment. Operating income for GEN-NE was $21 million for the year ended December 31, 2004, compared to $46 million for the year ended December 31, 2003. This decrease was primarily the result of pricing effects year over year, as increased fuel costs more than offset an increase in power prices. This resulted in a $21 million reduction in earnings. Additionally, we realized $11 million less revenue in 2004 under a transitional power purchase agreement, which expired in October 2004. Operating expense in GEN-NE was up $3 million year over year as a result of increased labor and tax expense. However, these reductions in earnings were partially offset by a 7% increase in volumes, which contributed an additional $6 million, largely the result of the dual fuel capabilities of our Roseton unit. GEN-NE results also included $17 million and $20 million of mark-to-market gains in 2004 and 2003, respectively. Depreciation increased slightly, from $9 million in 2003 to $10 million in 2004, while general and administrative expense remained flat at $13 million in both periods.

Power Generation—South Segment. Operating loss for GEN-SO was $52 million for the year ended December 31, 2004, compared to a loss of $48 million for the year ended December 31, 2003. Results from our peaking facilities in the Southeast decreased by $25 million, primarily as a result of the loss of capacity revenues related to a contract that expired at the end of 2003. Results from our ERCOT facility improved by $8 million, from a loss of $20 million in 2003 to a loss of $12 million in 2004. Additionally, 2003 results included a charge of $11 million related to a comprehensive settlement agreement with a manufacturer of turbines in which we agreed in principle to forfeit a prepayment in the amount of $11 million. GEN-SO results included mark-to-market losses of $8 million and $6 million in 2004 and 2003, respectively. Depreciation decreased from $30 million in 2003 to $25 million in 2004.

CRM. Operating loss for the CRM segment was $118 million for 2004, compared to operating loss of $385 million in 2003.

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; and

•

Results for 2003 were impacted by the following pre-tax losses:

•

$133 million charge associated with the settlement of power tolling arrangements with Southern Power, for which we paid $155 million;

•

$121 million mark-to-market loss on contracts associated with the Independence power tolling arrangement;

•

$34 million charge associated with the cash settlement of the Batesville tolling arrangement; and

•

$30 million charge associated with the settlement of power supply agreements with Kroger, for which we received approximately $110 million.

Additionally, 2003 results include gains from the sale of natural gas inventories offset by changes in the value of our remaining marketing and trading activity, and fixed payments on our power tolling arrangements in excess of realized margins on power generated and sold.

Index to Financial Statements

REG. Operating income for the REG segment was $139 million in 2004, which included income prior to our sale of Illinois Power to Ameren on September 30, 2004, compared to a loss of $327 million in 2003. The 2004 period includes a $58 million charge related to the loss on the sale of Illinois Power and a $54 million impairment of Illinois Power assets. We also stopped depreciating our Illinois Power assets on February 1, 2004, as they were classified as held for sale, which resulted in a benefit to operating income of $111 million compared to the 2003 period. The 2003 period includes an operating loss for the fourth quarter 2003 of $485 million, which was not experienced in 2004, due to the September 2004 sale of Illinois Power. Included in the fourth quarter 2003 activity is a $529 million charge for the impairment of goodwill and other assets associated with this segment, as further described in Note 11—Goodwill and Intangible Assets beginning on page F-42 and $30 million of depreciation expense.

Operationally, residential and commercial electric sales volumes for the first nine months of 2004 were negatively impacted by warmer than average winter weather compared to 2003. Industrial electric sales were negatively affected by customers choosing alternate energy providers. These decreases were more than offset by lower overall operating costs, which were primarily due to the reimbursement of MISO exit fees and RTO development costs totaling approximately $10 million and lower departmental spending, partially offset by higher employee benefit costs. Residential and commercial electric sales volumes were relatively flat in 2004 as compared to 2003 due to cooler summer weather offset by warmer spring weather.

Other. Other operating loss was $284 million in 2004, compared to $251 million in 2003. The losses in 2004 and 2003 primarily relate to general and administrative expenses and depreciation and amortization expenses which are incurred at a corporate level. The higher loss in 2004 related primarily to increased legal and settlement charges, costs related to compliance with Section 404 of the Sarbanes-Oxley Act and higher professional fees.

Operating loss for 2004 includes approximately $92 million of expenses related to legal and settlement charges. Operating loss for 2003 includes legal charges of $50 million. The legal charges in both periods resulted from additional activities during each period that affected management’s assessment of the probable and estimable loss associated with the applicable proceedings.

Earnings from Unconsolidated Investments.

Earnings from unconsolidated investments were $192 million for the year ended December 31, 2004, compared to $126 million for the year ended December 31, 2003.

Power Generation—Midwest Segment. Earnings from unconsolidated investments for GEN-MW were $80 million for the year ended December 31, 2004, compared to $15 million for the year ended December 31, 2003. Both periods included $7 million of earnings related to our Rocky Road investment, which we own 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. 2003 earnings include $5 million and $3 million from Michigan Power and Joppa, respectively.

Power Generation—South Segment. Earnings from unconsolidated investments for GEN-SO were $112 million for 2004, compared with earnings of $113 million for 2003.

Our West Coast Power investment was the primary driver of equity earnings for 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 $15 million on the sale of our 50% interest in the Oyster Creek facility in Texas. In addition

Index to Financial Statements

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 and $5 million from our investment in Black Mountain (Nevada Cogeneration).

West Coast Power’s Earnings of $137 million for 2003 were partially offset by a $20 million charge associated with our 50% share of a goodwill impairment charge recorded by West Coast Power in the fourth quarter 2003. Earnings of $22 million from our remaining U.S. and international investments were more than offset by a $26 million impairment.

CRM. CRM’s losses from unconsolidated investments were zero during 2004 compared to $2 million in 2003. As of December 31, 2003, CRM has no material unconsolidated investments. As such, future results are expected to be immaterial.

Other Items, Net

Other items, net consists of other income and expense items, net, minority interest income (expense) and accumulated distributions associated with trust preferred securities. Other items, net totaled $9 million and $37 million for 2004 and 2003, respectively.

The 2004 results included $12 million in interest income.

The 2003 results included the following items:

•

$17 million in interest income;

•

$20 million in minority interest income;

•

$11 million gain on foreign currency transactions; offset by

•

$8 million charge for accumulated distributions associated with trust preferred securities.

Interest Expense

Interest expense totaled $453 million for 2004, compared with $503 million for 2003.

The decrease in 2004, as compared to 2003, is primarily attributable to the following:

•

Lower average principal balances in the 2004 period (approximately $69 million of the decrease);

•

Decreased amortization of debt issuance costs (approximately $28 million of the decrease);

•

Lower letter of credit fees (approximately $12 million of the decrease). The lower letter of credit fees resulted from the restructuring of our credit facility in May 2004, with respect to which such fees are lower than those contained in our previous facility.

These items were offset by higher average interest rates on borrowings (approximately $61 million), including the new notes issued in connection with our August 2003 refinancing.

Income Tax Benefit

We reported an income tax benefit from continuing operations of $172 million in 2004, compared to an income tax benefit from continuing operations of $296 million in 2003. These amounts reflect effective rates of 49% and 27%, respectively. The 2004 tax benefit includes a $27 million benefit related to a reduction in a deferred tax capital losses valuation allowance associated with gains on asset sales and a $9 million benefit primarily related to IRS and state audits and settlements and other items. The 2003 effective rate was impacted significantly by the $311 million goodwill impairment relating to the REG segment. As there was no tax basis in

Index to Financial Statements

the goodwill impaired in 2003, there were no tax benefits associated with the charge. Additionally, the 2003 tax benefit includes a $21 million reduction in a valuation allowance associated with our capital loss carryforward as a result of capital gains recognized in 2003 or anticipated to be recognized in early 2004 related to various dispositions. Excluding these items from the 2004 and 2003 calculations would result in effective tax rates of 39% and 34%, 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-49 for further discussion of our income taxes.

Discontinued Operations

Year Ended December 31, 2004


	U.K. CRM		DGC		NGL			Other		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

Year Ended December 31, 2003


	U.K. CRM			DGC		NGL			Other			Total
	(in millions)
Operating income included in income from discontinued operations	$	(10	)	$	7	$	173		$	(2	)	$	168
Earnings from unconsolidated investments included in income from discontinued operations		—			—		(2	)		—			(2	)
Other items, net included in income from discontinued operations		(21	)		—		(17	)		—			(38	)
Interest expense included in income from discontinued operations													(6	)

Income from discontinued operations before taxes													122
Income tax expense													(41	)

Income from discontinued operations												$	81

As further discussed in Note 4—Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Natural Gas Liquids beginning on page F-28, on October 31, 2005, we completed the sale of DMSLP which comprised the NGL segment prior to the sale. As a result of the sale and as required by SFAS No. 144, we have reclassified the operations of the remaining NGL segment, primarily related to DMSLP, from continuing operations to discontinued operations.

In 2004, pre-tax income from discontinued operations of $276 million ($165 million after-tax income) included $254 million in pre-tax income attributable to NGL. In 2003, pre-tax income from discontinued operations of $122 million ($81 million after-tax) included $148 million in pre-tax income attributable to NGL.

Index to Financial Statements

Included in NGL’s 2004 pre-tax income are 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 at our Puckett gas processing facility. NGL’s pre-tax income for 2003 included a $25 million gain on sale of our ownership interest in the Hackberry LNG facility and a $3 million gain associated with the expiration of an environmental indemnity obligation. Additionally, NGL’s 2003 results were negatively impacted by a $12 million pre-tax impairment on our minority investment in GCF related to the difference between our book value and indicative bids received related to the possible sale of our minority investment.

In accordance with EITF Issue 87-24, “Allocation of Interest to Discontinued Operations,” 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 $27 million and $6 million for 2004 and 2003, respectively.

Income Tax Expense From Discontinued Operations. We reported an income tax expense from discontinued operations of $111 million in 2004, compared to an income tax expense from discontinued operations of $41 million in 2003. These amounts reflect effective rates of 40% and 34%, respectively. The 2004 tax expense includes $20 million in tax expenses related to the conclusion of prior year tax audits partially offset by translation gains recognized on the repatriation of cash from the U.K. Please read Note 14—Income Taxes beginning on page F-49 for further discussion. Excluding this item from the 2004 calculations would result in an effective tax rate of 33%. 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.

Cumulative Effect of Change in Accounting Principles

We reflected EITF Issue 02-03’s rescission of EITF Issue 98-10 effective January 1, 2003 as a cumulative effect of change in accounting principle. The net impact was a pre-tax benefit of $33 million ($21 million after-tax), of which a benefit of $43 million was recognized in our CRM segment and a charge of $10 million was recognized in our Generation business. We also adopted SFAS No. 143 effective January 1, 2003 and recognized a pre-tax benefit of $54 million ($34 million after-tax) associated with its implementation. The $54 million benefit was split between our power generation business ($57 million) and our REG segment ($(3) million). Finally, we adopted certain provisions of FIN No. 46R in the fourth quarter 2003 and recognized a pre-tax charge of $23 million ($15 million after-tax) in our GEN-SO segment related to our CoGen Lyondell facility.

Please read Note 2—Accounting Policies beginning on page F-13 for further discussion of our adoption of recent accounting policies.

2006 Outlook

The following summarizes our 2006 outlook for our power generation business and our customer risk management business.

Power Generation Business. Generally, we expect that future financial results of the generation business will continue to reflect sensitivity to underlying fuel commodity prices and market prices for energy, ancillary services and capacity, transportation and transmission logistics, weather conditions and in-market asset availability. Although we will continue our efforts to manage price risk through the optimization of fuel procurement, we expect to limit long-term forward sales of power and related transactions in order to capture short-term market pricing opportunities. Adverse changes in prices will expose us to lower earnings.

GEN- MW. We expect our results to continue to be impacted by power prices in the market and fuel availability. Although we expect prices to continue to remain high in the Midwest, we will not be able to fully

Index to Financial Statements

realize these prices, due to volume options held by AmerenIP in our power purchase agreement with them. Under the terms of our power purchase agreement, which expires at the end of 2006, AmerenIP can take up to 2800 MW of energy and ancillary services in each hour at $30/MWh from May-September and up to 2300 MW of energy and ancillary services in each hour at $30/MWh during the other months. However, the PPA contains quarterly and annual limitations on the amount of MWhs that AmerenIP can take. Additionally, AmerenIP may request up to another 150 MW in each hour at a market based price. Beyond 2006, results in the Midwest will be affected by expiration of this power purchase agreement. Expiration of this contract will result in increased exposure to volatility in market prices, and could allow us to realize additional benefits in a strong price environment.

Another factor impacting our results in the Midwest beyond 2006 will be the regulatory environment in Illinois. In January 2006, the Illinois Commerce Commission approved proposals by the two major Illinois electric utilities to hold an auction as the means by which they will procure capacity and energy necessary to serve load after 2006. While the ICC issued orders approving a reverse auction process, there remains a possibility of substantial challenges to these orders and the power of the ICC to issue them. Thus it is difficult to predict (i) whether an auction or some other mechanism(s), if any, will be approved in advance of 2007, and (ii) what impact an auction or lack thereof will have on our results.

Operation of our Midwest generation facilities is dependent on our ability to procure coal. Power generators have experienced significant pressures on available coal supplies that are either transportation or supply related. Our long-term supply and transportation agreements for our Midwest fleet largely mitigate these concerns; however, railroad maintenance has resulted in decreased delivery certainty since May 2005, especially in the month of October. Should this situation persist at levels similar to those experienced in 2005, we may re-implement a program to selectively conserve coal during off-peak periods, foregoing the revenue associated with this off-peak production to ensure adequate coal supply for on-peak load during 2006. A similar approach was successful in the fourth quarter of 2005. As a result, we expect we will be able to maintain an adequate level of coal inventories throughout 2006.

During 2005, our results reflected increases in the market for capacity-related products from our peaking and intermediate generation facilities. We benefited from operation of all of our peaking plants at certain times during the summer months of 2005. Based on increased demand and market design changes, including the implementation of a fully-functioning market in MISO in 2005, we continue to expect a contribution from our peaking and intermediate generation facilities in the summer months of 2006. This will be largely subject to the market demand and will therefore be heavily impacted by weather.

GEN-NE. We expect commodity fuel prices and market prices for energy and capacity to continue to be high, although these prices are off of the highs seen in the forward markets in the fall of 2005. Spreads are expected to remain volatile as fuel prices change. Warmer than normal temperatures at the start of 2006 have resulted in lower than expected demand in January. As a result, we expect year-to-year decreased runtime in the first half of 2006, particularly at our Roseton facility. Our results are also dependent on our ability to maintain coal and oil deliveries to the facilities. 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 18—Regulatory Issues—Roseton State Pollutant Discharge Elimination System Permit beginning on page F-67 and Note 18—Regulatory Issues—Danskammer State Pollutant Discharge Elimination System Permit beginning on page F-68, respectively.

GEN-SO. We entered into an agreement on September 6, 2005 to extend the steam and energy sales component of an ongoing relationship to 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 Chemical Company (“LCC”) for an initial term from January 2007 through December 2021 and subsequent automatic rollover terms of two years

Index to Financial Statements

each thereafter through December 2046. Expected incremental annual operating income of approximately $30 million for the ERCOT region beyond 2006 is associated primarily with this contract, which allows us to recover our operating costs. However, we retain our ability to capture market upside in the Texas region for the excess generation from Lyondell.

Our peaking facilities in the South continue to contribute revenue from sales of capacity to mainly the local load-serving entities or wholesale buyers. We currently have a substantial portion of our portfolio committed on an annual basis through 2015. Where we have uncommitted capacity and energy, we believe opportunities to sell additional capacity from these facilities will develop at times during the year. Due to the regulated, non-liquid market available in this region, our results will be impacted by our ability to complete additional sales to a limited pool of buyers for these products.

West Coast Power (our 50/50 joint venture co-owned with NRG Energy) was only a modest contributor to our 2005 profitability, and we expect mixed results for this business to continue until California’s efforts to re-formulate their wholesale electric market come to fruition. As a result, on December 27, 2005, we entered an agreement to sell our 50% interest to NRG Energy for $205 million. We expect this sale to close by early 2006; thus, West Coast Power will not materially contribute to our 2006 results. Please read Item 1. Business—Segment Discussion—Power Generation South Segment—South Fleet Equity Investments—West Coast Power beginning on page 14 of our Original Filing for a discussion of West Coast Power’s current contractual arrangements.

CRM. Our CRM business segment’s future results of operations will be significantly impacted by our ability to complete our exit from this business. Our CRM business remains a party to certain legacy gas and power transactions, most of which have been hedged. However, we expect to continue to incur cash outflows associated with the legacy transactions. In 2006, based on our current pricing forecasts, cash outflow from our CRM business, exclusive of the Sterlington settlement which closed on March 7, 2006, would be approximately $10 million, however this expectation would change with changes in commodity prices. We are proactively working with our customers to exit the remainder of our obligations on economically favorable terms.

Index to Financial Statements

CASH FLOW DISCLOSURES

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


	Years Ended December 31,
	2005			2004			2003
	(in millions)
Operating cash flows from our generation businesses	$	472		$	421		$	428
Operating cash flows from our customer risk management business		(21	)		(371	)		496
Operating cash flows from our natural gas liquids business		288			278			186
Operating cash flows from Illinois Power		—			213			67
Other operating cash flows		(769	)		(536	)		(301	)

Net cash provided by (used in) operating activities	$	(30	)	$	5		$	876

Operating Cash Flow. 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 Sterlington and Gregory power tolling arrangements 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 includes 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 12 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 power tolling arrangements and related 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 & 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.

Cash provided in 2003 relates primarily to collateral returns, settlements of risk management assets and sales of natural gas storage of approximately $500 million from our customer risk management business, a $110 million income tax refund and solid operational performances from our power generation business, our discontinued natural gas liquids business and Illinois Power. Despite a relatively weak commodity price environment, our power generation business provided cash flows in excess of $400 million, due largely to effective commercial and operational management and our coal- and dual-fired generation assets. Similarly, our discontinued natural gas liquids business contributed cash flows from operations in excess of $180 million due to a strong commodity price environment, particularly in the upstream business, offset by increases in prepayments

Index to Financial Statements

and lower downstream results due to industry-wide reductions in volumes available for fractionation. Illinois Power contributed operating cash flows in excess of $60 million, primarily from normal operating conditions, offset by working capital outflows due to increased injection of gas into storage, as well as an increase in prepayments. General and administrative costs, a $45 million litigation settlement and continued extinguishment of liabilities during our exit from our communications business offset these positive operational cash flows during 2003.

Capital Expenditures and Investing Activities. 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 maintenance capital 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 maintenance capital 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 collaterized 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 primarily to maintenance capital 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.

Cash used in investing activities for 2003 totaled $266 million. Our capital spending totaled $333 million and was primarily comprised of routine capital maintenance of our existing asset base. Of this amount, we spent approximately $40 million on the construction of Rolling Hills, which began commercial operations in June

Index to Financial Statements

2003. Our proceeds from asset sales totaled approximately $72 million and primarily relate to our sale of Hackberry LNG Terminal LLC ($35 million), SouthStar ($20 million), and generation equity investments ($25 million), which were offset by $10 million in cash outflows associated with the sale of our European communications business.

Financing Activities. 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 outstanding revolver due May 2007 in November 2005;

•

$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 stock and distributions of $25 million to minority interest owners.

Net cash used in financing activities during the 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 stock and made distributions to minority interest owners totaling $32 million.

During 2003, cash used for financing activities totaled $900 million. The following summarizes significant items:

•

Repayments of $128 million, net, under our revolving credit facilities.

•

Long-term debt proceeds, net of issuance costs, for 2003 totaled $2.2 billion and consisted of: (1) $311 million associated with the October 2003 follow-on offering of the DHI notes; (2) $1,607 million associated with our August 2003 refinancing transaction, (3) $142 million from the delayed issuance of $150 million in Illinois Power 11.5% Mortgage Bonds due 2010 and (4) $159 million from the Term A loan drawn in connection with the April 2003 credit facility restructuring.

•

In connection with the Series B Exchange, we made a $225 million cash payment to Chevron.

•

Repayments of long-term debt totaled $2.7 billion and consisted of: (1) $696 million prepayment of the outstanding balance under the Black Thunder financing; (2) $609 million purchase of DHI’s previously outstanding 2005/2006 senior notes; (3) $360 million prepayment of the Term B loan outstanding under DHI’s April 2003 restructured credit facility; (4) $200 million prepayment of the Term A loan

Index to Financial Statements

outstanding under DHI’s April 2003 restructured credit facility; (5) $200 million in payments under the Renaissance and Rolling Hills interim financing; (6) $190 million in payments of Illinois Power mortgage bond maturities; (7) $100 million payment on Illinois Power’s term loan; (8) $165 million payment in full for the GEN facility capital lease; (9) $86 million in payments on Illinois Power’s transitional funding trust notes; (10) $74 million in payments under the ABG Gas Supply financing; (11) $62 million in payments under the Black Thunder secured financing prior to its prepayment; (12) $5 million purchase of Illinova senior notes on the open market; and (13) $2 million in payments on the Chevron junior notes.

•

Distributions to minority interest owners totaling $21 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 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;

•

Valuation of Tangible and Intangible Assets;

•

Estimated Useful Lives;

•

Accounting for Contingencies, Guarantees and Indemnifications;

•

Accounting for Income Taxes; and

•

Valuation of Pension Assets and Liabilities.

Revenue Recognition

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 has historically been 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

Index to Financial Statements

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.

Additionally, the accrual model was used to account for substantially all of the operations conducted in our NGL and REG segments. These segments consisted largely of processing and delivery operations. The business of these segments included the separation of natural gas liquids into their component parts from a stream of natural gas and the transportation or transmission or commodities through pipelines or over transmission lines. End sales from these businesses resulted in physical delivery of commodities to our wholesale, commercial, industrial and retail customers. We recognized revenue from these transactions when the product or service was delivered to a customer.

The fair value model has historically been used to account for forward physical and financial transactions, occurring primarily in the CRM segment and the power generation business, which meet the definition of a derivative contract as defined by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. 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. The FASB determined that the fair value model is the most appropriate method for accounting for these types of contracts. 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” exemption 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” exemption or as a cash flow hedge. Because derivative contracts can be accounted for in three different ways, and as the “normal purchase normal sale” exemption and cash flow and fair value hedge accounting are elective, the accounting treatment used by another party for a similar transaction could be different than 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” exemption, 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 deduction of 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 to be 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.

Valuation of Tangible and Intangible Assets

We evaluate long-lived assets, such as property, plant and equipment, investments and goodwill, when events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows sufficient to 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;

Index to Financial Statements

•

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, “Accounting for the Impairment or Disposal of Long-Lived Assets.” If an impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the related discounted cash flows of the assets and recording a loss if the resulting estimated fair value is less than the book value. For assets identified as held for sale, the book value is compared to the estimated fair value, which may also include estimates based upon comparables or quoted market prices, to determine if an impairment loss is required. Please read Note 5—Restructuring and Impairment Charges beginning on page F-30 for discussion of impairment charges we recognized for 2005, 2004 and 2003.

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,” and EITF No. 02-14, “Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock,” 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.

Estimated Useful Lives

The estimated useful lives of our long-lived assets are used to compute depreciation expense, future asset retirement obligations and are also 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 asset retirement obligations may be insufficient and impairments in carrying values of tangible and intangible assets may result.

Accounting for Contingencies, Guarantees and Indemnifications

We are involved in numerous lawsuits, claims, proceedings, joint venture audits and tax-related audits in the normal course of our operations. In accordance with SFAS No. 5, “Accounting for Contingencies,” 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 the balance sheet. 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.

Index to Financial Statements

Liabilities are recorded when 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” for disclosure and accounting of various guarantees and indemnifications entered into during the course of business. When a guarantee or indemnification subject of 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” and FIN No. 47 “Accounting for Conditional Asset Retirements,” we are required to record legal obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded at a discount, 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 on the amount or timing of the cash flow change, the change may have a material impact on our results of operations.

Accounting for Income Taxes

We follow the guidance in SFAS No. 109, “Accounting for Income Taxes,” 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 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, including our 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 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 change. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made.

Please read Note 14—Income Taxes beginning on page F-49 for further discussion of our accounting for income taxes and any change in our valuation allowance.

Index to Financial Statements

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 declined during 2005. Accordingly, at December 31, 2005, we used a discount rate of 5.52% for pension plans and 5.53% for other retirement plans, a decline of 23 and 22 basis points, respectively, from the 5.75% rate used as of December 31, 2004. This decline in the discount rate increased the underfunded status of the plans by $7 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 feel 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, 2006 is 8.25%, the same as 2005. We expect 2006 pension expense to be lower than 2005 pension expense by approximately $3 million, primarily due to the sale of DMSLP. The decrease will be partially offset by the discount rate discussed above and the passage of time.

On December 31, 2005, 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). In accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” as of December 31, 2005, we have recognized a charge to accumulated other comprehensive loss of $8 million (net of taxes of $5 million), which decreases stockholders’ equity. The charge to stockholders’ equity for the excess of additional pension liability over the unrecognized prior service cost represents a net loss not yet recognized as pension expense.

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, 2005			Impact on 2006 Expense
	(in millions)
Increase in Discount Rate—50 basis points	$	(15.5	)	$	(1.7	)
Decrease in Discount Rate—50 basis points		17.3			1.8
Increase in Expected Long-term Rate of Return—50 basis points		—			(0.6	)
Decrease in Expected Long-term Rate of Return—50 basis points		—			0.6

We expect to make $17 million in cash contributions related to our pension plans during 2006. In addition, it is likely that we will be required to continue to make contributions to the pension plans beyond 2006. 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 $12 million in 2007 and $18 million in 2008.

Index to Financial Statements

Please read Note 20—Employee Compensation, Savings and Pension Plans beginning on page F-73 for further discussion of our pension related assets and liabilities.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 2—Accounting Policies—Accounting Principles Adopted beginning on page F-22 for a discussion of recently issued accounting pronouncements affecting us. Specifically, 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, and we adopted other portions of FIN No. 46R effective December 31, 2003. We adopted SFAS No. 150 and EITF Issue 03-11 effective July 1, 2003. We adopted FIN No. 45 and SFAS No. 143 effective January 1, 2003.

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, 2005
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2005	$	(133	)
Risk-management losses recognized through the income statement in the period, net		(23	)
Cash paid related to risk-management contracts settled in the period, net		103
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other (2)		(59	)

Fair value of portfolio at December 31, 2005	$	(112	)

(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, which were partially offset by the $62 million risk-management asset acquired in connection with the Sithe Energies transaction.

The net risk-management liability of $112 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, 2005. 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			2006			2007			2008			2009		2010		Thereafter
	(in millions)
Mark-to-Market (1)(3)	$	(84	)	$	(5	)	$	(65	)	$	(19	)	$	2	$	—	$	3
Cash Flow (2)		(78	)		1			(64	)		(21	)		2		—		4

Index to Financial Statements

(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 liabilities at December 31, 2005 of $112 million on the consolidated balance sheets includes the $84 million herein as well as 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, 2005 were derived solely from market quotations instead of the combination of long-term valuation models and market quotations used in prior years. Following our Sithe Energies acquisition and the resulting restructuring of the Independence toll, we no longer use long-term valuation models, as our risk-management portfolio can be fully valued based on market quotations.

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 beginning on page 85 of our Original Filing.

Index to Financial Statements

Item 8. Financial Statements and Supplementary Data

Our financial statements and financial statement schedules are set forth at pages F-1 through F-110 inclusive, found at the end of this annual report, and are incorporated herein by reference.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). This evaluation included consideration of the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified by the SEC. This evaluation also considered the work completed relating to our compliance with Section 404 of the Sarbanes-Oxley Act of 2002, which is further described below.

Based on this evaluation, our CEO and CFO concluded that, as of December 31, 2005, as a result of the material weakness discussed below, our disclosure controls and procedures were not effective to ensure that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the requisite time periods and that such information is accumulated and communicated to management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure. Due to the material weakness discussed below, in preparing our financial statements at and for the year ended December 31, 2005, we performed additional procedures relating to the income tax provision in an attempt to ensure that such financial statements were fairly presented in all material respects in accordance with generally accepted accounting principles.

Management’s Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Our 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. 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. Under the supervision and with the participation of our management, including the CEO and CFO, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2005. In making this assessment, we used the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of our annual or interim financial statements would not be prevented or detected. As of December 31, 2005, we did not maintain effective controls over the completeness and accuracy of the tax provision and deferred income tax balances in accordance with generally accepted accounting principles. Specifically, our processes, procedures and controls related to the preparation, analysis and recording of the income tax provision were not effective to ensure that the deferred tax provision and deferred tax balances were recorded in accordance with generally accepted accounting principles. This control deficiency resulted in the restatement of our 2004 and 2003 annual consolidated financial statements, as well as audit adjustments to the 2005 income tax provision. This control deficiency also resulted in the restatement of the 2005 consolidated financial statements reported in this Annual Report on Form 10-K/A. Further, this control deficiency could result in a misstatement of the income tax provision and related deferred tax accounts and disclosures that would result in a material misstatement to the annual or interim consolidated financial statements

Index to Financial Statements

that would not be prevented or detected. Therefore, we have concluded that this control deficiency constitutes a material weakness.

Because of the material weakness described above management has concluded that, as of December 31, 2005, we did not maintain effective internal control over our financial reporting based on the criteria set forth in Internal Control—Integrated Framework issued by the COSO.

Our management had previously concluded that we did not maintain effective internal control over financial reporting as of December 31, 2005 because of the material weakness described above. Subsequent to the filing of our Annual Report on Form 10-K for the year ended December 31, 2005, we identified another adjustment related to our deferred income tax accounts. Accordingly, in this Annual Report on Form 10-K/A, we have restated our consolidated financial statements. We have concluded that the restatement was an additional effect of the material weakness discussed above. Accordingly, this restatement does not affect the previous conclusion stated in our report on internal control over financial reporting.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report, which appears on page F-2.

Changes in Internal Control over Financial Reporting. We made no changes in our internal control over financial reporting during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act).

Remediation of Material Weakness. We previously reported in our 2004 Form 10-K that we did not maintain effective internal control over financial reporting as of December 31, 2004 due to the same material weakness discussed above. During 2005, actions were taken to remediate the material weakness reported in our 2004 Form 10-K, including: (i) increased levels of review in the preparation of the quarterly and annual tax provisions; (ii) formalized processes, procedures and documentation standards relating to the income tax provision; and (iii) restructured our Tax Department to ensure appropriate segregation of duties regarding preparation and review of the quarterly and annual tax provision. Despite these efforts, when making management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005, we determined that those controls were still not operating effectively.

In addition to continuing the enhanced processes implemented in 2004 and 2005 and described above, during 2006, we plan to take the following steps in an attempt to remediate the material weakness as of December 31, 2005: (i) implement new processes around the analysis of the income tax provision, including detailed reconciliations between book basis and tax basis of significant tax sensitive balance sheet accounts; (ii) implement additional procedures around the identification, analysis and recording of the tax effects of significant transactions; and (iii) further formalize and document the procedures around the preparation and review of the tax provision and tax accounts. We will not be able to conclude that the material weakness has been successfully remediated, and we cannot assure you we will be able to make such conclusion, until the testing of controls demonstrates that such controls have operated effectively for a sufficient period of time.

Index to Financial Statements

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a) The following documents, which we have filed with the SEC pursuant to the Securities Exchange Act of 1934, as amended, are by this reference incorporated in and made a part of this annual report:

1. Financial Statements—Our consolidated financial statements are incorporated under Item 8. of this annual report.

2. Financial Statement Schedules—Financial Statement Schedules are incorporated under Item 8. of this annual report.

3. Exhibits—The following instruments and documents are included as exhibits to this annual report. All management contracts or compensation plans or arrangements set forth in such list are marked with a ††.


Exhibit Number		Description
2.1		—Purchase Agreement dated February 2, 2004 among Dynegy Inc., Illinova Corporation, Illinova Generating Company and Ameren Corporation (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on February 4, 2004, File No. 1-15659).

3.1		—Amended and Restated Articles of Incorporation of Dynegy Inc. (incorporated by reference to Appendix A to the Definitive Proxy Statement on Schedule 14A of Dynegy Inc., File No. 1-15659, filed with the SEC on April 25, 2001).

3.2		—Statement of Resolution Establishing Series of Series C Convertible Preferred Stock of Dynegy Inc. (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

3.3		—Amended and Restated Bylaws of Dynegy Inc. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K of Dynegy Inc. filed on November 21, 2005, File No. 1-15659).

4.1		—Indenture, dated as of December 11, 1995, by and among NGC Corporation, the Subsidiary Guarantors named therein and the First National Bank of Chicago, as Trustee (incorporated by reference to exhibits to the Registration Statement on Form S-3 of NGC Corporation, Registration No. 33-97368).

4.2		—First Supplemental Indenture, dated as of August 31, 1996, by and among NGC Corporation, the Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.4 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1996 of NGC Corporation, File No. 1-11156).

4.3		—Second Supplemental Indenture, dated as of October 11, 1996, by and among NGC Corporation, the Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1996 of NGC Corporation, File No. 1-11156).

4.4		—Fourth Supplemental Indenture among NGC Corporation, Destec Energy, Inc. and The First National Bank of Chicago, as Trustee, dated as of June 30, 1997, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.12 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1997 of NGC Corporation, File No. 1-11156).

Index to Financial Statements


Exhibit Number		Description
4.5		—Fifth Supplemental Indenture among NGC Corporation, The Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, dated as of September 30, 1997, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.18 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1997 of NGC Corporation, File No. 1-11156).

4.6		—Sixth Supplemental Indenture among NGC Corporation, The Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, dated as of January 5, 1998, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.19 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1997 of NGC Corporation, File No. 1-11156).

4.7		—Seventh Supplemental Indenture among NGC Corporation, The Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, dated as of February 20, 1998, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.20 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1997 of NGC Corporation, File No. 1-11156).

4.8		—Eighth Supplemental Indenture dated July 25, 2003 that certain Indenture, dated as of December 11, 1995, between Dynegy Holdings Inc. and Wilmington Trust Company, as trustee (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Dynegy Inc. filed on July 28, 2003, File No. 1-15659).

4.9		—Subordinated Debenture Indenture between NGC Corporation and The First National Bank of Chicago, as Debenture Trustee, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).

4.10		—Amended and Restated Declaration of Trust among NGC Corporation, Wilmington Trust Company, as Property Trustee and Delaware Trustee, and the Administrative Trustees named therein, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.6 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).

4.11		—Series A Capital Securities Guarantee Agreement executed by NGC Corporation and The First National Bank of Chicago, as Guarantee Trustee, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.9 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).

4.12		—Common Securities Guarantee Agreement of NGC Corporation dated as of May 28, 1997 (incorporated by reference to Exhibit 4.10 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).

4.13		—Registration Rights Agreement, dated as of May 28, 1997, among NGC Corporation, NGC Corporation Capital Trust I, Lehman Brothers, Salomon Brothers Inc. and Smith Barney Inc. (incorporated by reference to Exhibit 4.11 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).

4.14		—Indenture, dated as of September 26, 1996, restated as of March 23, 1998, and amended and restated as of March 14, 2001, between Dynegy Holdings Inc. and Bank One Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.17 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2000 of Dynegy Holdings Inc., File No. 0-29311).

Index to Financial Statements


Exhibit Number		Description
4.15		—First Supplemental Indenture dated July 25, 2003 to that certain Indenture, dated as of September 26, 1996, between Dynegy Holdings Inc. and Wilmington Trust Company, as trustee (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on July 28, 2003, File No. 1-15659).

4.16		—Exchange and Registration Rights Agreement (Preferred Stock) dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

4.17		—Amended and Restated Registration Rights Agreement (Common Stock) dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.4 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

4.18		—Amended and Restated Shareholder Agreement dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

4.19		—Indenture dated as of August 11, 2003 among Dynegy Holdings Inc., the guarantors named therein, Wilmington Trust Company, as trustee, and Wells Fargo Bank Minnesota, N.A., as collateral trustee, including the form of promissory note for each series of notes issuable pursuant to the Indenture (incorporated by reference to Exhibit 4.8 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

4.20		—Indenture dated August 11, 2003 between Dynegy Inc., Dynegy Holdings Inc. and Wilmington Trust Company, as trustee, including the form of debenture issuable pursuant to the Indenture (incorporated by reference to Exhibit 4.9 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

4.21		—Registration Rights Agreement dated August 11, 2003 among Dynegy Inc., Dynegy Holdings Inc. and the initial purchasers named therein (incorporated by reference to Exhibit 4.10 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

4.22		—Trust Indenture dated as of January 1, 1993, among Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P. and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.22 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659).

4.23		—First Supplemental Indenture dated as of January 1, 1993 to the Trust Indenture dated as of January 1, 1993, among Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P. and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.23 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659).

4.24		—Second Supplemental Indenture dated as of October 23, 2001 to the Trust Indenture dated as of January 1, 1993, among Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P. and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.24 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659).

4.25		—Global Note representing the 8.50% Secured Bonds due 2007 of Sithe/Independence Power Partners, L.P. (incorporated by reference to Exhibit 4.4 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2005 of Dynegy Inc., File No. 1-15659).

Index to Financial Statements


Exhibit Number		Description
4.26		—Global Note representing the 9.00% Secured Bonds due 2013 of Sithe/Independence Power Partners, L.P. (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2005 of Dynegy Inc., File No. 1-15659).

		There have not been filed or incorporated as exhibits to this annual report, other debt instruments defining the rights of holders of our long-term debt, none of which relates to authorized indebtedness that exceeds 10% of our consolidated assets. We hereby agree to furnish a copy of any such instrument not previously filed to the SEC upon request.

10.1		—Dynegy Inc. Amended and Restated 1991 Stock Option Plan (incorporated by reference to Exhibit 10.3 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156). ††

10.2		—Dynegy Inc. 1998 U.K. Stock Option Plan (incorporated by reference to Exhibit 10.4 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156). ††

10.3		—Dynegy Inc. Amended and Restated Employee Equity Option Plan (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156). ††

10.4		—Dynegy Inc. 1999 Long Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156). ††

10.5		—Dynegy Inc. 2000 Long Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156). ††

10.6		—Dynegy Inc. 2001 Non-Executive Stock Incentive Plan (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76080). ††

10.7		—Dynegy Inc. 2002 Long Term Incentive Plan (incorporated by reference to Appendix A to the Definitive Proxy Statement on Schedule 14A of Dynegy Inc., File No. 1-15659, filed with the SEC on April 9, 2002). ††

10.8		—Extant, Inc. Equity Compensation Plan (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-47422). ††

10.9		—Employment Agreement, dated October 18, 2002, between Bruce A. Williamson and Dynegy Inc. (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2002 of Dynegy Inc., File No. 1-15659). ††

10.10		—First Amendment to October 18, 2002 Employment Agreement dated August 17, 2005 between Bruce A. Williamson and Dynegy Inc. (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).

10.11		—Second Amendment to October 18, 2002 Employment Agreement dated September 15, 2005 between Bruce A. Williamson and Dynegy Inc. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659).

10.12		—Contract for Consulting Services dated March 19, 2004 between Dynegy Inc. and Daniel L. Dienstbier (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2004 of Dynegy Inc., File No. 1-15659). ††

10.13		—Severance Agreement and Release dated December 31, 2005 between Dynegy Inc. and Carol F. Graebner (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on January 6, 2006, File No. 1-15659). ††

Index to Financial Statements


Exhibit Number		Description
10.14		—Severance Agreement and Release dated December 31, 2005 between Dynegy Inc. and R. Blake Young (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on January 6, 2006, File No. 1-15659).††

10.15		—Dynegy Inc. 401(k) Savings Plan, as amended and restated effective January 1, 2002 (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 383-76570). ††

10.16		—First Amendment to the Dynegy Inc. 401(k) Savings Plan, effective February 11, 2002 (incorporated by reference to Exhibit 10.19 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659). ††

10.17		—Second Amendment to the Dynegy Inc. 401(k) Savings Plan, effective January 1, 2002 (incorporated by reference to Exhibit 10.20 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659). ††

10.18		—Third Amendment to the Dynegy Inc. 401(k) Savings Plan, effective October 1, 2003 (incorporated by reference to Exhibit 10.21 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659). ††

10.19		—Amendment to the Dynegy Inc. 401(k) Savings Plan, effective January 1, 2004 (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659). ††

10.20		—Dynegy Inc. 401(k) Savings Plan Trust Agreement (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76570). ††

10.21		—Dynegy Inc. Deferred Compensation Plan (incorporated by reference to Exhibit 4.6 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76080). ††

10.22		—Dynegy Inc. Deferred Compensation Plan Trust Agreement (incorporated by reference to Exhibit 4.7 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76080). ††

10.23		—Dynegy Inc. Short-Term Executive Stock Purchase Loan Program (incorporated by reference to Exhibit 10.19 to the Annual Report on Form 10-K for the Year Ended December 31, 2001 of Dynegy Inc., File No. 1-15659). ††

10.24		—Dynegy Inc. Deferred Compensation Plan for Certain Directors (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659). ††

10.25		—First Amendment to the Dynegy Inc. Deferred Compensation Plan for Certain Directors dated September 15, 2005 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659). ††

10.26		—Second Amendment to the Dynegy Inc. Deferred Compensation Plan for Certain Directors dated December 16, 2005 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on December 22, 2005, File No. 1-15659). ††

10.27		—Dynegy Inc. Executive Severance Pay Plan as amended and restated effective as of February 1, 2005 (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659). ††

10.28		—First Amendment to the Dynegy Inc. Executive Severance Pay Plan dated September 15, 2005 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659). ††

Index to Financial Statements


Exhibit Number		Description
10.29		—Second Amendment to the Dynegy Inc. Executive Severance Pay Plan dated October 31, 2005 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659). ††

10.30		—Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated November 20, 2003 (incorporated by reference to Exhibit 99.4 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659). ††

10.31		—First Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated June 22, 2005 (incorporated by reference to Exhibit 99.5 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659). ††

10.32		—Second Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated September 15, 2005 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659). ††

10.33		—Third Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated October 31, 2005 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659). ††

10.34		—Dynegy Inc. Mid-Term Incentive Performance Award Program (incorporated by reference to Exhibit 10.29 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659). ††

*10.35		—Termination of the Dynegy Inc. Mid-Term Incentive Performance Award Program effective January 1, 2006.††

*10.36		—Dynegy Inc. Incentive Compensation Plan, as amended and restated effective January 1, 2006. ††

10.37		—Dynegy Northeast Generation, Inc. Savings Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-111985). ††

10.38		—Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan, effective January 1, 2004 (incorporated by reference to Exhibit 10.31 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659). ††

10.39		—Dynegy Inc. Severance Pay Plan, as amended and restated effective February 1, 2005 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659). ††

10.40		—First Amendment to the Dynegy Inc. Severance Pay Plan dated October 31, 2005 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659). ††

*10.41		—Second Amendment to the Dynegy Inc. Severance Pay Plan dated December 14, 2005.††

10.42		—First Supplemental Plan to the Dynegy Inc. Severance Pay Plan dated June 22, 2005 (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659). ††

10.43		—First Amendment to the First Supplemental Plan to the Dynegy Inc. Severance Pay Plan dated October 31, 2005 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659). ††

10.44		—Lease Agreement entered into on June 12, 1996 between Metropolitan Life Insurance Company and Metropolitan Tower Realty Company, Inc., as landlord, and NGC Corporation, as tenant (incorporated by reference to Exhibit 10.69 to the Registration Statement on Form S-4 of Midstream Combination Corp., Registration No. 333-09419).

Index to Financial Statements


Exhibit Number		Description
10.45		— First Amendment to Lease Agreement entered into on June 12, 1996 between Metropolitan Life Insurance Company and Metropolitan Tower Realty Company, Inc., as landlord, and NGC Corporation, as tenant (incorporated by reference to Exhibit 10.70 to the Registration Statement on Form S-4 of Midstream Combination Corp., Registration No. 333-09419).

10.46		—Amended and Restated Credit Agreement dated as of May 28, 2004 among Dynegy Holdings Inc., as Borrower, Dynegy Inc., as Parent Guarantor, the Other Guarantors Party Thereto, the Lenders Party Thereto and Various Other Parties Thereto (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on June 1, 2004, File No. 1-15659).

10.47		—Second Amended and Restated Credit Agreement dated as of October 31, 2005 among Dynegy Holdings Inc., as Borrower, and Dynegy Inc., as Parent Guarantor (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659).

10.48		—Third Amended and Restated Credit Agreement dated as of March 6, 2006 among Dynegy Holdings Inc., as Borrower, and Dynegy Inc., as Parent Guarantor (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 9, 2006, File No. 1-15659).

10.49		—Shared Security Agreement, dated April 1, 2003, among Dynegy Holdings, Inc., various grantors named therein, Wilmington Trust Company, as corporate trustee, and John M. Beeson, Jr., as individual trustee (incorporated by reference to Exhibit 10.32 to the Annual Report on Form 10-K for the Year Ended December 31, 2002 of Dynegy Inc., File No. 1-15659).

10.50		—Non-Shared Security Agreement, dated April 1, 2003, among Dynegy Inc., various grantors named therein and Bank One, N.A. as collateral agent (incorporated by reference to Exhibit 10.33 to the Annual Report on Form 10-K for the Year Ended December 31, 2002 of Dynegy Inc., File No. 1-15659).

10.51		—Collateral Trust and Intercreditor Agreement, dated as of April 1, 2003, among Dynegy Holdings Inc., various grantors named therein, Wilmington Trust Company, as corporate trustee, and John M. Beeson, Jr., as individual trustee (incorporated by reference to Exhibit 10.34 to the Annual Report on Form 10-K for the Year Ended December 31, 2002 of Dynegy Inc., File No. 1-15659).

10.52		—Amendment No. 1 to Collateral Trust and Intercreditor Agreement, dated as of May 28, 2004, among Dynegy Holdings Inc., various grantors named therein, JPMorgan Chase Bank, as collateral agent, Wilmington Trust Company, as corporate trustee, and John M. Beeson, Jr., as individual trustee (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2004 of Dynegy Inc., File No. 1-15659).

10.53		—Series B Preferred Stock Exchange Agreement dated as of July 28, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

10.54		—Indemnity Agreement dated August 11, 2003 among Dynegy Inc., Dynegy Holdings Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

10.55		—Intercreditor Agreement dated August 11, 2003 among Dynegy Holdings Inc., various grantors named therein, Wilmington Trust Company, as corporate trustee, John M. Beeson, Jr., as individual trustee, Bank One, NA, as collateral agent, and Wells Fargo Bank Minnesota, N.A., as collateral trustee (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

Index to Financial Statements


Exhibit Number		Description

10.56		—Second Lien Shared Security Agreement dated August 11, 2003 among Dynegy Holdings Inc., various grantors named therein and Wells Fargo Bank Minnesota, N.A., as collateral trustee (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).
10.57		—Second Lien Non-Shared Security Agreement dated August 11, 2003 among Dynegy Inc., various grantors named therein and Wells Fargo Bank Minnesota, N.A., as collateral trustee (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

10.58		—Purchase Agreement dated August 1, 2003 among Dynegy Inc., Dynegy Holdings Inc. and the initial purchasers named therein (incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

10.59		—Purchase Agreement dated August 1, 2003 among Dynegy Holdings Inc., the guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

10.60		—Purchase Agreement dated September 30, 2003 among Dynegy Holdings Inc., the guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on October 15, 2003, File No. 1-15659).

10.61		—Power Purchase Agreement dated September 30, 2004 between Illinois Power Company and Dynegy Power Marketing, Inc. (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 2004 of Dynegy Inc., File No. 1-15659).

10.62		—Escrow Agreement dated as of September 30, 2004 among Illinova Corporation, Ameren Corporation and JPMorgan Chase Bank, as escrow agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 2004 of Dynegy Inc., File No. 1-15659).

10.63		—Stock Purchase Agreement dated as of November 1, 2004 among Dynegy New York Holdings Inc., Exelon SHC, Inc., Exelon New England Power Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.48 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659)

10.64		—Amendment to Stock Purchase Agreement (Special Payroll Payment) dated as of January 28, 2005 among Dynegy New York Holdings Inc., Exelon SHC, Inc., Exelon New England Power Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659)

10.65		—Amendment to Stock Purchase Agreement dated as of January 31, 2005 among Dynegy New York Holdings Inc., Exelon SHC, Inc., Exelon New England Power Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659)

10.66		—Amendment to Stock Purchase Agreement (Luz Sale) dated as of January 31, 2005 among Dynegy New York Holdings Inc., Exelon SHC, Inc., Exelon New England Power Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659)

10.67		—Tenth Amendment to Amended and Restated Base Gas Sales Agreement, dated as of June 29, 2001, by and between Enron North America Corp. and Sithe/Independence Power Partners, L.P. (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659)

10.68		—Power Purchase Agreement dated November 17, 2004 between Dynegy Power Marketing, Inc. as seller, and Constellation Energy Commodities Group, Inc., as purchaser. (incorporated by reference to Exhibit 10.53 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659)

Index to Financial Statements


Exhibit Number		Description
10.69		—Assignment and Assumption Agreement dated as of November 17, 2004 between Dynegy Power Marketing, Inc. and Constellation Energy Commodities Group, Inc. (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659)

10.70		—Partnership Interest Purchase Agreement dated as of August 2, 2005 among Dynegy Inc, Dynegy Holdings Inc., Dynegy Midstream Holdings, Inc., and Dynegy Midstream G.P., Inc. as Sellers and Targa Resources, Inc., Targa Resources Partners OLP LP, and Targa Midstream GP, LLC as Buyers (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).

10.71		—Steam and Electric Power Sales Agreement dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).

10.72		—Services Agreement for CLI Facility dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).

10.73		—Amended and Restated Lease and Easement Agreement dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).

10.74		—Guaranty Agreement dated as of September 6, 2005 by Dynegy Holdings Inc. on behalf of Cogen Lyondell, Inc. in favor of Lyondell Chemical Company (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).

10.75		—Termination Agreement and Release dated as of December 23, 2005 between Quachita Power, LLC and Dynegy Power Marketing, Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on December 28, 2005, File No. 1-15659).

10.76		—Purchase Agreement (Rocky Road Power) dated December 27, 2005 between NRG Rocky Road LLC, NRG Energy, Inc., Termo Santander Holding, L.L.C. and Dynegy Inc. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on December 28, 2005, File No. 1-15659).

10.77		—Purchase Agreement (West Coast Power) dated December 27, 2005 between NRG West Coast LLC, NRG Energy, Inc., DPC II Inc. and Dynegy Inc. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on December 28, 2005, File No. 1-15659).

10.78		—Stipulation of Settlement dated May 2, 2005 (Shareholder Class Action Litigation) (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2005 of Dynegy Inc., File No. 1-15659).

10.79		—Stipulation of Settlement dated April 29, 2005 (Shareholder Derivative Litigation) (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2005 of Dynegy Inc., File No. 1-15659).

10.80		—Baldwin Consent Decree approved May 27, 2005 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 31, 2005, File No. 1-15659).

10.81		—Director Compensation Summary (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 24, 2005, File No. 1-15659). ††

Index to Financial Statements


Exhibit Number		Description
14.1		—Dynegy Inc. Code of Ethics for Senior Financial Professionals (incorporated by reference to Exhibit 14.1 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1- 15659).

*21.1		—Subsidiaries of the Registrant.

**23.1		—Consent of PricewaterhouseCoopers LLP.

**23.2		—Consent of PricewaterhouseCoopers LLP (West Coast Power LLC).

**31.1		—Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

**31.2		—Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

†32.1		—Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

†32.2		—Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Previously filed

**	Filed herewith

†

Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act.

Index to Financial Statements

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	DYNEGY INC.

Date: May 1, 2006	By:	/s/ HOLLI C. NICHOLS
		Holli C. Nichols Executive Vice President and Chief Financial Officer

Index to Financial Statements

DYNEGY INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


		Page
Consolidated Financial Statements (Restated)
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2005 and 2004		F-5
Consolidated Statements of Operations for the years ended December 31, 2005, 2004 and 2003		F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003		F-7
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2005, 2004 and 2003		F-8
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2005, 2004 and 2003		F-9
Notes to Consolidated Financial Statements		F-10

Financial Statement Schedules
Schedule I – Parent Company Financial Statements (Restated)		F-88
Schedule II – Valuation and Qualifying Accounts (Restated)		F-92

West Coast Power LLC Consolidated Financial Statements*		F-93

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

F-1

Index to Financial Statements

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 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements 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, 2005 and December 31, 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 the Restatement Note, the 2005 consolidated financial statements have been restated. As discussed in the Explanatory Note, the 2004 and 2003 consolidated financial statements have been restated.

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.

As discussed in Note 2, the Company adopted the provisions of Emerging Issues Task Force Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” and Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” as of December 31, 2005. As discussed in Note 2, the Company adopted the provisions of Emerging Issues Task Force Issue No. 04-8, “The Effect of Contingently Convertible Instruments on Diluted Earnings per Share,” as of January 1, 2004. As discussed in Note 2, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” as of January 1, 2003. As discussed in Note 2, the Company adopted the net presentation provisions of Emerging Issues Task Force Issue No. 02-3, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as of January 1, 2002 and the provision related to the rescission of Emerging Issues Task Force Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as of January 1, 2003. As discussed in Note 2, the Company adopted Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation,” using the prospective method of transition prescribed by Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure,” as of January 1, 2003.

F-2

Index to Financial Statements

Internal control over financial reporting

Also, we have audited management’s assessment, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, that Dynegy Inc. did not maintain effective internal control over financial reporting as of December 31, 2005, because the Company did not maintain effective controls over the completeness and accuracy of the tax provision and deferred income tax balances in accordance with generally accepted accounting principles, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (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.

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.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weakness has been identified and included in management’s assessment. As of December 31, 2005, the Company did not maintain effective controls over the completeness and accuracy of the tax provision and deferred income tax balances in accordance with generally accepted accounting principles. Specifically, the Company’s processes, procedures and controls related to the preparation, analysis and recording of the income tax provision were not effective to ensure that the deferred tax provision and deferred tax balances were recorded in accordance with generally accepted accounting principles. This control deficiency resulted in the restatement of the Company’s 2004 and 2003 annual consolidated financial statements as well as audit adjustments to the 2005 income tax provision. Further, this control deficiency could result in a misstatement of the income tax provision and related deferred tax accounts and disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Therefore, the Company concluded that this control deficiency constitutes a material weakness. This material weakness was considered in determining the nature, timing, and extent of audit tests

F-3

Index to Financial Statements

applied in our audit of the 2005 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements.

In our opinion, management’s assessment that Dynegy Inc. did not maintain effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the COSO. Also, in our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Dynegy Inc. has not maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the COSO.

Management and we previously concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2005 because of the material weakness described above. In connection with the restatement of the Company’s consolidated financial statements described in the Restatement Note to the consolidated financial statements, management has determined that the restatement was an additional effect of the material weakness described above. Accordingly, this restatement did not affect management’s assessment or our opinions on internal control over financial reporting.

PricewaterhouseCoopers LLP

Houston, Texas

March 14, 2006, except for the Restatement Note to the consolidated financial statements and the matter discussed in the penultimate paragraph of Management’s Report on Internal Control over Financial Reporting, as to which the date is May 1, 2006.

F-4

Index to Financial Statements

DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

See Restatement Note and Explanatory Note

(in millions, except share data)


	December 31, 2005			December 31, 2004
	(Restated)			(Restated)
ASSETS
Current Assets
Cash and cash equivalents	$	1,549		$	628
Restricted cash		397			—
Accounts receivable, net of allowance for doubtful accounts of $103 and $159, respectively		611			810
Accounts receivable, affiliates		29			14
Inventory		214			221
Assets from risk-management activities		665			565
Deferred income taxes		14			62
Prepayments and other current assets		227			428

Total Current Assets		3,706			2,728

Property, Plant and Equipment		6,515			7,822
Accumulated depreciation		(1,192	)		(1,692	)

Property, Plant and Equipment, Net		5,323			6,130
Other Assets
Unconsolidated investments		270			421
Restricted investments		85			—
Assets from risk-management activities		165			313
Goodwill		—			15
Intangible assets		392			—
Deferred income taxes		3			15
Other long-term assets		182			221

Total Assets	$	10,126		$	9,843

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	504		$	557
Accounts payable, affiliates		46			23
Accrued interest		159			118
Accrued liabilities and other current liabilities		649			454
Liabilities from risk-management activities		687			616
Notes payable and current portion of long-term debt		71			34

Total Current Liabilities		2,116			1,802

Long-term debt		4,028			4,132
Long-term debt to affiliates		200			200

Long-Term Debt		4,228			4,332
Other Liabilities
Liabilities from risk-management activities		255			395
Deferred income taxes		558			499
Other long-term liabilities		429			353

Total Liabilities		7,586			7,381

Minority Interest		—			106
Commitments and Contingencies (Note 17)
Redeemable Preferred Securities, redemption value of $400 at December 31, 2005 and December 31, 2004 (Note 15)		400			400
Stockholders’ Equity
Class A Common Stock, no par value, 900,000,000 shares authorized at December 31, 2005 and December 31, 2004; 305,129,052 and 285,012,203 shares issued and outstanding at December 31, 2005 and December 31, 2004, respectively		2,949			2,859
Class B Common Stock, no par value, 360,000,000 shares authorized at December 31, 2005 and December 31, 2004; 96,891,014 shares issued and outstanding at December 31, 2005 and December 31, 2004		1,006			1,006
Additional paid-in capital		51			41
Subscriptions receivable		(8	)		(8	)
Accumulated other comprehensive income (loss), net of tax		4			(13	)
Accumulated deficit		(1,793	)		(1,861	)
Treasury stock, at cost, 1,714,026 and 1,679,183 shares at December 31, 2005 and December 31, 2004, respectively		(69	)		(68	)

Total Stockholders’ Equity		2,140			1,956

Total Liabilities and Stockholders’ Equity	$	10,126		$	9,843

See the notes to the consolidated financial statements.

F-5

Index to Financial Statements

DYNEGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

See Restatement Note

(in millions, except per share data)


	Year Ended December 31,
	2005			2004			2003
	(Restated)
Revenues	$	2,313		$	2,451		$	2,599
Cost of sales, exclusive of depreciation shown separately below		(2,416	)		(1,850	)		(2,150	)
Depreciation and amortization expense		(220	)		(235	)		(373	)
Goodwill impairment		—			—			(311	)
Impairment and other charges		(46	)		(78	)		(225	)
Gain (loss) on sale of assets, net		(1	)		(58	)		6
General and administrative expenses		(468	)		(330	)		(315	)

Operating loss		(838	)		(100	)		(769	)
Earnings from unconsolidated investments		2			192			126
Interest expense		(389	)		(453	)		(503	)
Other income and expense, net		26			12			25
Minority interest income (expense)		—			(3	)		20
Accumulated distributions associated with trust preferred securities		—			—			(8	)

Loss from continuing operations before income taxes		(1,199	)		(352	)		(1,109	)
Income tax benefit		395			172			296

Loss from continuing operations		(804	)		(180	)		(813	)
Income from discontinued operations, net of tax expense of $357, $111 and $41, respectively (Note 4)		899			165			81

Income (loss) before cumulative effect of change in accounting principles		95			(15	)		(732	)
Cumulative effect of change in accounting principles, net of tax benefit (expense) of $2, zero and $(24), respectively (Note 2)		(5	)		—			40

Net income (loss)		90			(15	)		(692	)
Less: preferred stock dividends (gain) (Note 13)		22			22			(1,013	)

Net income (loss) applicable to common stockholders	$	68		$	(37	)	$	321

Earnings (Loss) Per Share (Note 16):
Basic earnings (loss) per share:
Earnings (loss) from continuing operations	$	(2.13	)	$	(0.53	)	$	0.53
Income from discontinued operations		2.32			0.43			0.22
Cumulative effect of change in accounting principles		(0.01	)		—			0.11

Basic earnings (loss) per share	$	0.18		$	(0.10	)	$	0.86

Diluted earnings (loss) per share:
Earnings (loss) from continuing operations	$	(2.13	)	$	(0.53	)	$	0.50
Income from discontinued operations		2.32			0.43			0.19
Cumulative effect of change in accounting principles		(0.01	)		—			0.09

Diluted earnings (loss) per share	$	0.18		$	(0.10	)	$	0.78

Basic shares outstanding		387			378			374
Diluted shares outstanding		513			504			423

See the notes to the consolidated financial statements.

F-6

Index to Financial Statements

DYNEGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

See Restatement Note

(in millions)


		Year Ended December 31,
		2005			2004			2003
		(Restated)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	90		$	(15	)	$	(692	)
Adjustments to reconcile income (loss) to net cash flows from operating activities:
Depreciation and amortization			284			356			525
Goodwill impairment			—			—			311
Impairment and other charges			46			83			225
(Earnings) losses from unconsolidated investments, net of cash distributions			73			(66	)		33
Risk-management activities			46			(50	)		382
(Gain) loss on sale of assets, net			(1,096	)		(11	)		(57	)
Deferred taxes			(73	)		(74	)		(258	)
Cumulative effect of change in accounting principles (Note 2)			5			—			(40	)
Reserve for doubtful accounts			1			—			19
Liability associated with gas transportation contracts (Note 4)			—			(148	)		—
Independence toll settlement charge (Note 3)			169			—			—
Legal and settlement charges			119			104			58
Sterlington toll settlement charge (Note 4)			364			—			—
Other			22			(40	)		(67	)
Changes in working capital:
Accounts receivable			(134	)		4			1,683
Inventory	</