Edgar Filing: DYNEGY INC.

Form 10-K for fiscal year ended December 31, 2007

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2007

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

For the transition period from to

DYNEGY INC.

DYNEGY HOLDINGS INC.

(Exact name of registrant as specified in its charter)


Entity	Commission File Number	State of Incorporation	I.R.S. Employer Identification No.
Dynegy Inc.	001-33443	Delaware	20-5653152
Dynegy Holdings Inc.	000-29311	Delaware	94-3248415

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

(713) 507-6400

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section12(b) of the Act:


Title of each class		Name of each exchange on which registered
Dynegy’s Class A common stock, $0.01 par value		New York Stock Exchange

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


Title of each class		Name of each exchange on which registered
None		None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.


Dynegy Inc.		Yes x No ¨
Dynegy Holdings Inc.		Yes ¨ No x

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.


Dynegy Inc.		Yes ¨ No x
Dynegy Holdings Inc.		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.


Dynegy Inc.		Yes x No ¨
Dynegy Holdings Inc.		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.


Dynegy Inc.		x
Dynegy Holdings Inc.		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	Accelerated filer	Non-accelerated filer
Dynegy Inc.	x	¨	¨
Dynegy Holdings Inc.	¨	¨	x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).


Dynegy Inc.		Yes ¨ No x
Dynegy Holdings Inc.		Yes ¨ No x

As of June 30, 2007, the aggregate market value of the Dynegy Inc. common stock held by non-affiliates of the registrant was $4,725,779,593 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: For Dynegy Inc., Class A common stock, $0.01 par value per share, 500,478,928 shares outstanding as of February 21, 2008; Class B common stock, $0.01 par value per share, 340,000,000 shares outstanding as of February 21, 2008. All of Dynegy Holdings Inc.’s outstanding common stock is owned indirectly by Dynegy Inc.

This combined Form 10-K is separately filed by Dynegy Inc. and Dynegy Holdings Inc. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to a registrant other than itself.

DOCUMENTS INCORPORATED BY REFERENCE-Dynegy Inc. Part III (Items 10, 11, 12, 13 and 14) incorporates by reference portions of the Notice and Proxy Statement for the registrant’s 2008 Annual Meeting of Stockholders, which the registrant intends to file not later than 120 days after December 31, 2007.

REDUCED DISCLOSURE FORMAT-Dynegy Holdings Inc. Dynegy Holdings Inc. meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and therefore is filing this Form 10-K with the reduced disclosure format.

DYNEGY INC. and DYNEGY HOLDINGS INC.

FORM 10-K

TABLE OF CONTENTS


		Page

	PART I
Definitions		1
Item 1.	Business—Dynegy Inc. and Dynegy Holdings Inc.	1
Item 1A.	Risk Factors—Dynegy Inc. and Dynegy Holdings Inc.	20
Item 1B.	Unresolved Staff Comments—Dynegy Inc. and Dynegy Holdings Inc.	30
Item 2.	Properties—Dynegy Inc. and Dynegy Holdings Inc.	30
Item 3.	Legal Proceedings—Dynegy Inc. and Dynegy Holdings Inc.	30
Item 4.	Submission of Matters to a Vote of Security Holders—Dynegy Inc.	30

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Dynegy Inc.	31
Item 6.	Selected Financial Data—Dynegy Inc. and Dynegy Holdings Inc.	34
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations—Dynegy Inc. and Dynegy Holdings Inc.	37
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk—Dynegy Inc. and Dynegy Holdings Inc.	84
Item 8.	Financial Statements and Supplementary Data—Dynegy Inc. and Dynegy Holdings Inc.	87
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure—Dynegy Inc. and Dynegy Holdings Inc.	87
Item 9A.	Controls and Procedures—Dynegy Inc. and Dynegy Holdings Inc.	87
Item 9B.	Other Information—Dynegy Inc. and Dynegy Holdings Inc.	88

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance—Dynegy Inc.	89
Item 11.	Executive Compensation—Dynegy Inc.	89
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—Dynegy Inc.	90
Item 13.	Certain Relationships and Related Transactions and Director Independence—Dynegy Inc.	90
Item 14.	Principal Accountant Fees and Services—Dynegy Inc.	90

	PART IV
Item 15.	Exhibits, Financial Statement Schedules—Dynegy Inc. and Dynegy Holdings Inc.	91
Signatures		104

Explanatory Note

This report includes the combined filing of Dynegy Inc. (“Dynegy”) and Dynegy Holdings Inc. (“DHI”). DHI is the principal subsidiary of Dynegy, providing approximately 100 percent of Dynegy’s total consolidated revenue for the year ended December 31, 2007 and constituting approximately 100 percent of Dynegy’s total consolidated asset base as of December 31, 2007 except for Dynegy’s 50 percent interest in DLS Power Holdings, LLC (“DLS Power Holdings”) and DLS Power Development Company, LLC (“DLS Power Development”).

On March 29, 2007, at a special meeting of the shareholders of Dynegy Illinois Inc. (“Dynegy Illinois”), the shareholders of Dynegy Illinois (i) adopted the Plan of Merger, Contribution and Sale Agreement, dated as of September 14, 2006 (the “Merger Agreement”), by and among Dynegy, Dynegy Illinois, Falcon Merger Sub Co., an Illinois corporation and a then-wholly owned subsidiary of Dynegy, LSP Gen Investors, L.P., LS Power Partners, L.P., LS Power Equity Partners PIE I, L.P., LS Power Equity Partners, L.P. and LS Power Associates, L.P. (“LS Associates” and, collectively, the “LS Contributing Entities”) and (ii) approved the merger of Merger Sub Co. (“Merger Sub”), with and into Dynegy Illinois (together with the Merger Agreement the “Merger”). On April 2, 2007, in accordance with the Merger Agreement, (i) the Merger was effected, as a result of which Dynegy Illinois became a wholly owned subsidiary of Dynegy and each share of the Class A common stock and Class B common stock of Dynegy Illinois outstanding immediately prior to the Merger was converted into the right to receive one share of the Class A common stock of Dynegy, and (ii) the LS Contributing Entities transferred all of the interests owned by them in entities that own eleven power generation facilities to Dynegy (the “Contributed Entities”). Upon completion of the Merger, Dynegy contributed its interest in the Contributed Entities to DHI.

In April 2007, Dynegy contributed to DHI its interest in Dynegy New York Holdings Inc. (“New York Holdings”). New York Holdings together with its wholly owned subsidiaries, owns the 1,064 MW Independence power generation facility located near Scriba, New York, as well as natural gas-fired merchant facilities in New York and hydroelectric generation facilities in Pennsylvania (the “Sithe Assets”). This contribution was accounted for as a transaction between entities under common control. This form 10-K with respect to DHI reflects the contribution as though DHI had owned New York Holdings in all periods presented. Please see Note 3—Business Combinations and Acquisitions—Sithe Assets Contribution for further discussion.

Unless the context indicates otherwise, throughout this report, the terms “the Company”, “we”, “us”, “our” and “ours” are used to refer to both Dynegy and DHI and their direct and indirect subsidiaries, including Dynegy Illinois before it became a wholly owned subsidiary of Dynegy by way of the Merger. Discussions or areas of this report that apply only to Dynegy or DHI are clearly noted in such discussions or areas.

PART I

DEFINITIONS

As used in this Form 10-K, the abbreviations contained herein have the meanings set forth in the glossary, which can be found in the Notes to Consolidated Financial Statements.

Item 1. Business

THE COMPANY

We are holding companies and conduct substantially all of our business operations through our subsidiaries. Our primary business is the production and sale of electric energy, capacity and ancillary services from our fleet of twenty-nine operating power plants in thirteen states totaling nearly 20,000 MW of generating capacity.

During 2007, we completed the LS Power combination, through which we acquired ten power generation facilities (approximately 8,000 MW) that are primarily natural gas-fired and intermediate dispatch. These facilities nearly doubled our generating capacity, added significant additional diversity to our portfolio and provided us with scale and scope in the key Western U.S. region. Dynegy also acquired a fifty percent interest in a development joint venture, which provides Dynegy with access to resources experienced in power development that are focused on growth prospects, both brownfield and greenfield. We believe that our larger, more diverse asset base positions us to realize the benefits associated with increasing power prices and tightening reserve margins across the United States.

Dynegy began operations in 1985. DHI is a wholly owned subsidiary of Dynegy. Dynegy became incorporated in the State of Delaware in 2007 as a part of the LS Power transaction. Our principal executive office is located at 1000 Louisiana Street, Suite 5800, Houston, Texas 77002, and our telephone number at that office is (713) 507-6400.

We file annual, quarterly and current reports, proxy statements (for Dynegy Inc.) and other information with the SEC. You may read and copy any document we file at the SEC’s Public Reference Room at 100 F Street N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SEC’s Public Reference Room. Our SEC filings are also available to the public at the SEC’s web site at www.sec.gov. No information from such web site is incorporated by reference herein. Our SEC filings are also available free of charge on our web site at www.dynegy.com, as soon as reasonably practicable after those reports are filed with or furnished to the SEC. The contents of our website are not intended to be, and should not be considered to be, incorporated by reference into this Form 10-K.

Our Business

We sell electric energy, capacity, and ancillary services on a wholesale basis from our power generation facilities. Energy is the actual output of electricity and is measured in MWh. The capacity of a generation facility is its electricity production capability, measured in MW. Wholesale electricity customers will, for reliability reasons and to meet regulatory requirements, contract for rights to capacity from generating units. Ancillary services are the products of a generation facility that support the transmission grid operation, follow real-time changes in load and provide emergency reserves for major changes to the balance of generation and load. We sell these products individually or in combination to our customers under short- and long-term contractual agreements or tariffs.

Our customers include RTOs and ISOs, integrated utilities, municipalities, electric cooperatives, transmission and distribution utilities, industrial customers, power marketers, financial participants such as banks and hedge funds, other power generators and commercial end-users. All of our products are sold on a wholesale basis for various lengths of time from hourly to multi-year transactions. Some of our customers, such as

municipalities or integrated utilities, purchase our products for resale in order to serve their retail, commercial and industrial customers. Other customers, such as some power marketers, may buy from us to serve their own wholesale or retail customers or as a hedge against power sales they have made.

Our Strategy

Our business strategy is designed to leverage our diverse portfolio of generating assets, our operational and commercial skills and our flexible capital structure to create value for our investors. In general, we seek to maximize the value of our assets through:

•

Safe and cost-efficient plant operations, with a focus on having our plants available and “in the market” when it is economical to do so;

•

A diverse commercial strategy that includes short-, medium- and long-term sales of energy, capacity and ancillary services, and seeks to strike a balance between contracting for a base level of earnings and cash flows and maintaining merchant strength to capitalize on expected increases in commodity prices;

•

Pursuit of plant expansions and new-build development projects with acceptable rates of return; and

•

Participation in growth opportunities that enhance our portfolio and are accretive to stockholder value.

Maintain a Diverse Portfolio to Capitalize on Market Opportunities and Mitigate Risk. We operate a balanced portfolio of generation assets that is diversified in terms of dispatch profile, fuel type and geography. In terms of dispatch type, we have a diverse mix of baseload, intermediate and peaking generation assets. Baseload generation is low-cost and economically attractive to dispatch around the clock throughout the year. A baseload facility is usually expected to run between 80 percent and 90 percent of the hours in a given year. Intermediate generation is not as efficient and/or economical as baseload generation but is intended to be dispatched during higher load times such as during daylight hours and sometimes on weekends. Peaking generation is the least efficient and highest cost generation and is generally dispatched to serve load during the highest load times such as hot summer and cold winter days.

We believe our substantial coal-fired, baseload fleet should continue to benefit from the impact of higher natural gas prices on power prices in the Midwest and Northeast, allowing us to capture greater margins. It is anticipated that our combined cycle units should benefit from improved margins and cash flows as supply and demand come more into balance in our key markets.

In addition, we seek to maintain a diverse portfolio of assets as a mitigant against the risks inherent in our business. For example, weather patterns, regulatory regimes and commodity prices often differ by region. By maintaining fleet diversity, we seek to mitigate these risks, and their resulting impact on the level and consistency of our earnings and cash flows, for the benefit of our investors. We also believe that this diversity is crucial in meeting growing U.S. power needs, which are expected to continue to increase at about two percent a year.

Our current operating generating facilities are as follows:


Facility	Total Net Generating Capacity (MW)(1)	Primary Fuel Type	Dispatch Type	Location	Region
Baldwin	1,800	Coal	Baseload	Baldwin, IL	MISO
Kendall	1,200	Gas	Intermediate	Minooka, IL	PJM
Ontelaunee	580	Gas	Intermediate	Ontelaunee Township, PA	PJM
Havana Units 1-5	228	Oil	Peaking	Havana, IL	MISO
Unit 6	441	Coal	Baseload	Havana, IL	MISO
Hennepin	293	Coal	Baseload	Hennepin, IL	MISO
Oglesby	63	Gas	Peaking	Oglesby, IL	MISO
Stallings	89	Gas	Peaking	Stallings, IL	MISO
Tilton	188	Gas	Peaking	Tilton, IL	MISO
Vermilion Units 1-2	164	Coal/Gas	Baseload	Oakwood, IL	MISO
Unit 3	12	Oil	Peaking	Oakwood, IL	MISO
Wood River Units 1-3	119	Gas	Peaking	Alton, IL	MISO
Units 4-5	446	Coal	Baseload	Alton, IL	MISO
Rocky Road (2)	330	Gas	Peaking	East Dundee, IL	PJM
Riverside/Foothills	960	Gas	Peaking	Louisa, KY	PJM
Rolling Hills	965	Gas	Peaking	Wilkesville, OH	PJM
Renaissance	776	Gas	Peaking	Carson City, MI	MISO
Bluegrass	576	Gas	Peaking	Oldham County, KY	SERC

Total Midwest	9,230

Moss Landing Units 1-2	1,020	Gas	Intermediate	Monterrey County, CA	CAISO
Units 6-7	1,509	Gas	Peaking	Monterrey County, CA	CAISO
Morro Bay (3)	650	Gas	Peaking	Morro Bay, CA	CAISO
South Bay	706	Gas/Oil	Peaking	Chula Vista, CA	CAISO
Oakland	165	Oil	Peaking	Oakland, CA	CAISO
Arlington Valley	585	Gas	Intermediate	Arlington, AZ	Southwest
Griffith	558	Gas	Intermediate	Golden Valley, AZ	WAPA
Calcasieu (4)	351	Gas	Peaking	Sulphur, LA	SERC
Heard County	539	Gas	Peaking	Heard County, GA	SERC
Black Mountain (5)	43	Gas	Baseload	Las Vegas, NV	WECC

Total West	6,126

Independence	1,064	Gas	Intermediate	Scriba, NY	NYISO
Roseton (6)	1,185	Gas/Oil	Peaking	Newburgh, NY	NYISO
Bridgeport	527	Gas	Intermediate	Bridgeport, CT	ISO-NE
Casco Bay	540	Gas	Intermediate	Veazie, ME	ISO-NE
Danskammer Units1-2	123	Gas/Oil	Peaking	Newburgh, NY	NYISO
Units 3-4 (6)	370	Coal/Gas	Baseload	Newburgh, NY	NYISO

Total Northeast	3,809

Total Fleet Capacity	19,165

(1)	Unit capacity values are based on winter capacity.

(2)	Does not include 28 MW of capacity for unit 3, which is not available during cold weather because of winterization requirements.

(3)	Represents units 3 and 4 generating capacity. Units 1 and 2, with a combined net generating capacity of 352 MW, are currently in lay-up status and out of operation.

(4)

On January 31, 2007, we entered into an agreement to sell our interest in the Calcasieu power generation facility to Entergy. The transaction is expected to close in the first half of 2008. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—GEN-WE Discontinued Operations—Calcasieu for further discussion.

(5)	We own a 50 percent interest in this facility and the remaining 50 percent interest is held by Chevron U.S.A. Inc. Total output capacity of this facility is 85 MW.

(6)

We lease the Roseton power generation facility and units 3 and 4 of the Danskammer power generation facility pursuant to a leveraged lease arrangement that is further described in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Off-Balance Sheet Arrangements—DNE Leveraged Lease.

Operate our Assets Safely and Cost-Efficiently to Maximize Revenue Opportunities and Operating Margins. We have a history of strong plant operations and are committed to operating our facilities in a safe, reliable and environmentally compliant manner. By maintaining and operating our assets so as to continually improve plant availability, dispatch and capacity factors and to maintain an appropriate level of operating and capital costs, we believe we are positioned to effectively capture opportunities in the market place and to maximize our operating margins.

With respect to cost controls, a key aspect of profitability is our cost to produce electricity. The main variable component of that cost is fuel. Our coal-fired generation facilities are our lowest variable cost facilities. Therefore, most of our coal-fired generation facilities run the majority of any given day throughout the year unless a particular unit is unavailable due to either planned or unplanned maintenance activity. In today’s environment, our natural gas and fuel oil-fired power generation facilities are more expensive to operate than our coal-fired facilities. As a result, these plants only run on those days, or parts of days, when market demand and price are sufficient to economically justify dispatch of these higher cost units.

We categorize the operations and maintenance (“O&M”) costs at our facilities as either fixed O&M or variable O&M. Fixed O&M is generally the non-fuel cost to maintain and operate a unit. This includes both major maintenance that must occur every few years to ensure reliability of a unit and routine maintenance, which must be performed more frequently. Variable O&M is the incremental cost that occurs for each dispatch, including fuel needed to start up a unit and the cost of consumables used during operation.

Our power generation facilities are managed to require a relatively predictable level of maintenance capital expenditures without compromising operational integrity. Our capital expenditures are for the continued maintenance of our facilities to ensure their continued reliability and for investment in new equipment for either environmental compliance or increasing profitability. We seek to operate and maintain our generation fleet efficiently and safely, with an eye toward future maintenance and improvements, resulting in increased reliability and environmental stewardship. This increased reliability impacts our results to the extent that our generation units are available during times that it is economically sound to run. For units which hold contracts for capacity, our ability to secure availability payments from customers is dependent on plant availability. We believe these ongoing efforts should allow us to maintain focus on being a reliable, low-cost producer of power.

Employ a Flexible Commercial Strategy to Maintain Market Upside Potential. We seek to optimize our assets by selling electricity and capacity when pricing is most attractive. This objective is best achieved through a diverse portfolio of assets commercialized through a combination of spot market sales and term contracts. Short-term power market prices are determined largely by the balance of supply and demand in a region and are heavily influenced by weather. Both short-term and long-term prices are also heavily impacted by the price of natural gas, which is also impacted by regional weather effects. In most markets in which we operate, power prices rise and fall in tandem with natural gas prices. In some markets in which we operate, there is an excess of power generation supply compared to demand. However, due to demand growth out-pacing supply growth, we expect that this excess supply will diminish over time as consumption continues to grow, likely resulting in increased market prices for power.

While we do not have a prescribed allocation of volumes between spot and term market sales, we generally intend to rely on our low-cost coal facilities and term contractual sales arrangements to provide a base level of cash flow, while preserving financial exposure to market prices. We believe this strategy will allow us to benefit from anticipated increases in both short-term and long-term market prices. Consequently, our financial results will be sensitive to, and generally correlated with, commodity prices (especially natural gas prices, regional power prices and the “spread” between them).

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

Execute on Development and Expansion Options to Grow the Portfolio. We have a number of options to expand our generation fleet including through Dynegy’s development joint venture with LS Power. The focus of the joint venture is on high-return greenfield and brownfield development projects that include natural gas, coal and renewable options. In our development activities, as in our operating business, we believe that a portfolio of supply options will provide the most economical and reliable source of energy while ensuring high standards of environmental stewardship. Our approach to meeting future power needs includes options to participate in the development of a portfolio of projects diverse in dispatch, fuel and location.

We believe that our interest in the joint venture can result in meaningful new sources of cash flow as we anticipate value either through the future operation and commercialization of new assets, the sale of portions of our interest in development options, or through expansion and facility replacement projects at our existing plants.

Utilize our Capital Structure to Support our Commercial Strategy. We believe that the power industry is a commodity cyclical business with significant commodity price volatility and considerable capital investment requirements. Thus, maximizing economic returns in this market environment requires a capital structure that can withstand power price volatility as well as a commercial strategy that captures the value associated with both short-term and long-term price trends. We believe we have a capital structure that is suitable for our commercial strategy and the commodity cyclical market in which we operate. Maintaining appropriate debt levels and covenants, maturities and overall liquidity are key elements of this capital structure. This structure allows us to be opportunistic as we regularly evaluate potential combinations or asset acquisitions.

SEGMENT DISCUSSION

Our business operations are focused primarily on the wholesale power generation sector of the energy industry. We report the results of our power generation business, based on geographical location and how we allocate resources, as three separate segments in our consolidated financial statements: (i) the Midwest segment (“GEN-MW”), (ii) the West segment (“GEN-WE”) and (iii) the Northeast segment (“GEN-NE”). We also separately report the results of our legacy CRM business, which includes commodity contracts and positions associated with our former marketing and trading business. As described below, our NGL business, which was conducted through DMSLP and its subsidiaries, was sold to Targa Resources, Inc. (“Targa”) on October 31, 2005. Our consolidated financial results also reflect corporate-level expenses such as general and administrative and interest. Please read Note 22—Segment Information for further information regarding the financial results of our business segments.

NERC Regions, RTOs and ISOs. In discussing our business, we often refer to North American Electric Reliability Corporation (“NERC”) regions. The NERC and its eight regional reliability councils (as of December 31, 2007) were formed to ensure the reliability and security of the electricity system. The regional reliability councils set standards for reliable operation and maintenance of power generation facilities and

transmission systems. For example, each NERC region establishes a minimum reserve requirement to ensure there is sufficient generating capacity to meet expected demand within its region. Each NERC region reports seasonally and annually on the status of generation and transmission in each region.

Separately, RTOs and ISOs administer the transmission infrastructure and markets across a regional footprint in some of the markets in which we operate. They are responsible for dispatching all generation facilities in that footprint, and are responsible for both maximum utilization and efficient operation of the transmission system within secure levels. RTOs and ISOs administer electricity markets in the short term, usually day ahead and real-time markets. Several RTOs and ISOs also ensure long-term planning reserves through monthly, semi-annual, annual and multi-year capacity markets. The ISOs or RTOs that oversee most of the wholesale power markets currently impose, and may continue to impose, price limits under their bidding rules. They may also enforce caps and other mechanisms to guard against the exercise of market power in these markets. NERC regions and RTOs/ISOs often have different geographic footprints and while there may be physical overlap, their respective roles and responsibilities do not overlap.

In regions with centrally dispatched market structures, all generators selling into the centralized market receive the same price for energy sold based on the price required to justify production of the last megawatt hour that is needed to balance supply with demand within a designated zone. For example, a less-efficient (i.e. more expensive) natural gas-fired unit may be needed in some hours to meet demand. If this unit’s production is required to meet demand, its production costs will set the market clearing price that will be paid for all dispatched generation, regardless of the price that any other unit may have offered into the market or its cost of generation. In other regions, prices are determined on a bilateral basis between buyers and sellers.

Market Based Rates. Our ability to charge market-based rates for wholesale sales of electricity, as opposed to cost-based rates, is governed by FERC. We have been granted market-based rate authority for wholesale power sales from our exempt wholesale generator facilities, which include all of our facilities except our investment in Nevada Cogeneration Associates #2 (“Black Mountain”). This facility is a QF, which has various exemptions from federal regulation and sells electricity directly to purchasers under negotiated and previously approved power purchase agreements. Our market-based rate authority is predicated on a finding by FERC that our facilities with market-based rates do not have market power. Our next triennial market power review must be filed with FERC in June 2008.

Power Generation—Midwest Segment

Our Midwest fleet is comprised of 15 facilities located in Illinois (10), Michigan (1), Ohio (1), Pennsylvania (1) and Kentucky (2), with a total capacity of 9,230 MW. With the exception of our Bluegrass peaking facility in the Louisville Gas and Electric control area, our Midwest fleet as of December 31, 2007 operates entirely within either the Midwest ISO (“MISO”) or the Pennsylvania-New Jersey-Maryland Interconnection (“PJM”).

RTO/ISO Discussion

MISO. At December 31, 2007, we owned nine power generating facilities with an aggregate net generating capacity of 4,619 MW located within MISO.

The MISO market includes all of Wisconsin and Michigan and portions of Ohio, Kentucky, Indiana, Illinois, Nebraska, Kansas, Missouri, Iowa, Minnesota, North Dakota, Montana and Manitoba, Canada.

MISO ensures that every electric industry participant has access to the grid and that no entity has the ability to deny access to a competitor. MISO also manages the use of transmission lines to make sure that they do not become overloaded. MISO operates physical and financial energy markets using a system known as Locational Marginal Pricing (“LMP”), which calculates a price for every generator and load point within the MISO area. This system is “price-transparent”, allowing generators and load serving entities to see real-time price effects of

transmission constraints and impacts of generation and load changes to prices at each point. MISO operates day-ahead and real-time markets into which generators can offer to provide energy. Financial Transmission Rights (“FTRs”) allow users to manage the cost of transmission congestion (the inability to physically move power from one location to another as a result of transmission limitations) and corresponding price differentials across the market area. MISO plans to implement a market for ancillary services in 2008 and an enforceable Planning Reserve Margin for the 2009-2010 planning year. An independent market monitor is responsible for ensuring that MISO markets are operating competitively and without exercise of market power.

PJM. At December 31, 2007, we owned five generating facilities located in Illinois (2), Pennsylvania (1), Kentucky (1) and Ohio (1) with an aggregate net generating capacity of 4,035 MW. The majority of power generated by these facilities is sold to wholesale customers in the PJM market.

The PJM market includes all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New York, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.

PJM administers markets for wholesale electricity and provides transmission planning for the region, utilizing the LMP system described above. PJM operates day-ahead and real-time markets into which generators can bid to provide electricity and ancillary services. PJM also administers markets for capacity. An independent market monitor continually monitors PJM markets for any exercise of market power or improper behavior by any entity. In addition, PJM recently implemented a forward capacity auction, the Reliability Pricing Model (“RPM”), which established long-term markets for capacity.

PJM, like MISO, dispatches power plants to meet system energy and reliability needs, and settles physical power deliveries at LMPs. This value is determined by an ISO-administered auction process, which evaluates and selects the least costly supplier offers or bids to create reliable and least-cost dispatch. The ISO-sponsored LMP energy markets consist of two separate and characteristically distinct settlement time frames. The first is a security-constrained, financially firm, day-ahead unit commitment market. The second is a security-constrained, financially settled, real-time dispatch and balancing market. Prices paid in these LMP energy markets, however, are affected by, among other things, market mitigation measures, which can result in lower prices associated with certain generating units that are mitigated because they are deemed to have the potential to exercise locational market power, and by $1,000/MWh energy market price caps that are in place.

Contracted Capacity and Energy

MISO. Approximately 73 percent of the expected generation from our MISO facilities is contracted for 2008. A portion of this contracted energy production is a result of our participation in the Illinois resource procurement auction, which resulted in energy product supply agreements with subsidiaries of Ameren Corporation (“Ameren”) for the following products:

•

Up to 1,200 MW in each hour around the clock through May 31, 2008, at the price of $64.77 per MWh; and

•

Up to 200 MW in each hour around the clock through May 31, 2009, at the price of $64.75 per MWh.

Under the terms of these agreements, we expect to deliver electricity together with capacity and specified ancillary services necessary to serve a portion of Ameren’s full-requirements residential and small customer load.

In addition to the energy committed under our contracts with Ameren, we expect all of our remaining energy production in the MISO region will be sold under a mix of bilateral contracts, over-the-counter energy sales (both physical and financial) and physical dispatches in the MISO energy market.

Approximately 74% of the capacity of our MISO facilities has been committed under bilateral capacity agreements through 2008, including commitments under the energy product supply agreements with Ameren described above.

PJM. All of the 4,035 MW of our PJM generating capacity is contracted for 2008. This was achieved through a combination of bilateral sales and sales into the new RPM auction. All of the expected 2008 energy production from our PJM facilities is contracted under various power purchase agreements, tolling agreements and bilateral contracts.

Regulatory Considerations

In January 2006, the ICC approved a reverse power procurement auction as the process by which utilities would procure power beginning in 2007. The initial auction occurred in September 2006, and we subsequently entered into two supplier forward contracts with subsidiaries of Ameren to provide capacity, energy and related services. The Illinois legislature passed legislation in 2007 as part of the Illinois rate relief package that significantly altered the power procurement process in Illinois; but the contracts with the Ameren subsidiaries remain in effect. Please read Note 19—Commitments and Contingencies—Legal Proceedings—Illinois Auction Complaints for further discussion.

In July 2007, legislative leaders in the State of Illinois announced a comprehensive transitional rate relief package for electric consumers. This program will provide approximately $1 billion to help provide assistance to utility customers in Illinois and fund a new power procurement agency. As part of this rate relief package, we will make payments of up to $25 million over a 29-month period. These payments will be contingent on certain conditions related to the absence of future electric rate and tax legislation in Illinois. We made a payment of $7.5 million in the third quarter 2007 and anticipate making payments of $9 million in 2008 and $8.5 million in 2009. Please read Note 19—Commitments and Contingencies—Legal Proceedings—Illinois Auction Complaints for further discussion.

Development Project

Plum Point. We own an approximate 37 percent interest in PPEA Holding Company LLC (“PPEA”), which in turn owns a 57 percent undivided interest in Plum Point, a new 665 MW coal-fired power generation facility under construction in Arkansas. Plum Point is currently in the construction phase, with an expected commercial operations date of August 2010. The joint owners of the Plum Point Project have selected us as the construction manager and as the operator of the facility when commercial operations commence.

Power Generation—West Segment

Our West fleet is comprised of eight predominantly natural gas-fired power generation facilities, located in California (3), Arizona (2), Louisiana (1), Georgia (1) and Nevada (1); and one fuel oil-fired power generation facility, located in California, totaling 6,126 MW of electric generating capacity.

RTO/ISO Discussion

CAISO. At December 31, 2007, we owned four generating facilities with an aggregate net generating capacity of 4,050 MW located within CAISO. The South Bay and Oakland facilities are designated as RMR units by the CAISO. MRTU, the CAISO’s new market design using nodal pricing, was scheduled to be implemented on April 1, 2008. This has been delayed to resolve technical issues and to allow for further testing. The current expected implementation date is May 1, 2008; however, this could be postponed to October 31, 2008. Please read “—Regulatory Considerations” below for further discussion.

Southwest Region. At December 31, 2007, we owned two combined cycle generating facilities with an aggregate net generating capacity of 1,143 MW located within the Southwest region. Griffith is subject to WAPA control area requirements, while Arlington Valley is in a generation-only control area operated by Constellation Energy (“Constellation”).

SERC. At December 31, 2007, we owned two natural gas-fired peaking generation facilities with an aggregate net generating capacity of 890 MW located in the SERC area. On January 31, 2007, we entered into an agreement to sell our interest in the Calcasieu power generation facility to Entergy. The transaction is expected to close in the first half of 2008. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—GEN-WE Discontinued Operations—Calcasieu for further discussion.

Contracted Capacity and Energy

CAISO. Approximately 60 percent of our 4,050 MW of CAISO generating capacity is contracted through 2008 under RMR or tolling arrangements. We have entered into an additional tolling agreement for 2009 through 2011, whereby we have contracted the full 650 MW capacity of our Morro Bay facility.

Including commitments under these tolling agreements, approximately 88 percent of our expected generation is contracted through 2008. Our remaining energy production in the CAISO region is sold directly to wholesale electricity customers in the spot market, predominantly via bilateral transactions. In order to mitigate the exposure of these facilities to changes in the market price of energy, we have entered into a financially-settled heat rate call-option agreement with respect to a portion of the energy generated at these facilities.

Southwest Region. Approximately 50 percent of our 1,143 MW generating capacity in the Southwest region is contracted under a tolling agreement from May through September, 2008. Including this commitment, approximately 72 percent of our expected energy production is contracted through 2008. The remaining energy is sold directly to wholesale electricity customers in the spot market. In order to mitigate the exposure of these facilities to changes in the market price of energy, we have entered into financially-settled heat rate call-option agreements with respect to a portion of the expected energy production from these facilities.

SERC. The Calcasieu and Heard County plants principally sell capacity to the local regulated utilities and energy and ancillary services through bilateral transactions with the utilities and wholesale buyers.

Regulatory Considerations

The CAISO is expected to implement MRTU, a new market design, sometime in 2008. The proposed implementation date is May 1, 2008, but could be postponed as late as October 31, 2008. The new model will dispatch units based on a least-cost approach and take into consideration transmission constraints and derates. This optimization approach should provide transparent locational pricing. The new design will also allow for physical and financial transactions and unbalanced schedules.

The CAISO, CPUC and CEC are also in preliminary discussions to restructure the current capacity market, referred to as Resource Adequacy. There are currently two recommendations under discussion. The first recommendation is to continue with the current bilateral market and possibly provide an electronic bulletin board for buyers and sellers. The second is a more robust recommendation that would provide a centralized capacity market where the CAISO, CPUC, and CEC would conduct six year projections of capacity requirements. Auctions would occur four years in advance of the delivery year with a price cap of 1.5 times the cost of new entry.

Equity Investment and Development Project

Black Mountain. We have a 50 percent ownership interest in the Black Mountain plant, which is a PURPA QF located near Las Vegas, Nevada, in the WECC. Capacity and energy from this facility are sold to Nevada Power Company under a long-term PURPA QF contract.

Sandy Creek. SCH has a 50 percent ownership interest in Sandy Creek Energy Associates, LP (“SCEA”), which owns a 75 percent undivided interest in the Sandy Creek Project, an 898 MW facility to be located in McLennan County, Texas. Construction has begun on this project, which we anticipate will begin commercial

operations in 2012. Of the expected plant output associated with SCEA’s 75 percent undivided interest, 150 MW is contracted for an initial 30-year period. The purchase contract provides for a pass-through of commodity fuel, transportation and emissions expenses. Similar contracts for additional output will be sought as plant construction proceeds. SCEA’s share of the construction is being financed through project debt and equity.

Power Generation—Northeast Segment

Our Northeast fleet is comprised of five facilities located in New York (3), Connecticut (1) and Maine (1), with a total capacity of 3,809 MW. We own and operate the Independence, Bridgeport, Casco Bay and Danskammer Units 1 and 2 power generating facilities, and we operate the Roseton and Danskammer Units 3 and 4 power generating facilities under long-term lease arrangements. Our Roseton and Danskammer facility sites are adjacent and share common resources such as fuel handling, a docking terminal, personnel and systems.

RTO/ISO Discussion

The Northeast region’s strategy is focused on optimizing the value of our broad and varied generation portfolio in the two interconnected and actively traded competitive markets: the NYISO and the ISO-NE. In the Northeast markets, load-serving entities generally lack their own generation capacity, with much of the generation base aging and with the current ownership of the generation spread among several operators. Thus, commodity prices are more volatile on an as-delivered basis than in other regions due to the distance and occasional physical constraints that impact the delivery of fuel into the region.

Although both Northeast ISOs and their respective energy markets are functionally, administratively and operationally independent, they follow, to a certain extent, similar market designs. Both ISOs dispatch power plants to meet system energy and reliability needs and settle physical power deliveries at LMPs as discussed above. The LMP market consists of two separate and characteristically distinct settlement time frames. The Northeast LMP, like the Midwest, has $1,000/MWh energy market price caps that are in place in both Northeast ISOs.

In addition to energy delivery, the Northeast ISOs manage secondary markets for installed capacity, ancillary services and FTRs.

NYISO. At December 31, 2007, three of our power generating facilities with an aggregate net generating capacity of 2,742 MW were located within the NYISO area. In 2003, NYISO implemented a “Demand Curve” mechanism for calculating the price and quantity of installed capacity to be procured statewide, with capacity prices influenced by the two locational zones: New York City/Long Island, and the rest of the state of New York. Our facilities operate outside of the New York City/Long Island locational zone.

Capacity pricing is calculated as a function of NYISO’s annual required reserve margin (16.5 percent for 2007-2008), the estimated cost of “new entrant” generation, estimated peak demand and the actual amount of capacity bid into the market. The Demand Curve mechanism provides for incrementally higher capacity pricing at lower reserve margins, such that “new entrant” economics become attractive as the reserve margin approaches required levels. The intent of the Demand Curve mechanism is to ensure that existing generation has enough revenue to maintain operations when capacity revenues are coupled with energy and ancillary service revenues. Additionally, the Demand Curve mechanism is intended to attract new investment in generation in the locations in which it is needed most.

Due to transmission constraints, energy prices vary across the state and are generally higher in the Eastern part of New York, where our Roseton and Danskammer facilities are located, and in New York City. (Our Independence facility is located in the Northwest part of the state.) Current reserve margins of 19 percent are somewhat above the NYISO’s required reserve margin of 16.5 percent. The New York State Reliability Council has proposed to lower the required reserve margin for 2008-2009 to 15 percent.

ISO-NE. At December 31, 2007, we owned and operated two power generating facilities with an aggregate net generating capacity of 1,067 MW located within the ISO-NE area. ISO-NE is in the process of implementing a forward capacity market, or FCM. ISO-NE instituted a transitional payment for capacity starting December 1, 2006, which starts at a price of $3.05/KW-month and gradually rises to $4.10/KW-month through June 1, 2010, when the FCM market will be fully effective.

Contracted Capacity and Energy

NYISO. Approximately 27 percent of our 2,742 MW of NYISO generating capacity is contracted through 2008. This contracted capacity relates to our Independence facility and is obligated under a capacity sales agreement that runs through 2014. Revenue from this capacity obligation is largely fixed with a variable discount that varies each month based on the price of power at Pleasant Valley LMP. Additionally, we supply steam and electric energy from our Independence facility to a third party at a fixed price and supply up to 44 MW to that third party under the agreement.

For the uncommitted portion of our Northeast fleet, due to the standard capacity market operated by NYISO and liquid over-the-counter market for NYISO capacity products, we are able to sell substantially all of our remaining capacity into the market each month. This provides relatively stable capacity revenues at market prices from our facilities both in the short-term and for the foreseeable future.

Approximately 78% of the expected energy production from our NYISO facilities is contracted through 2008 under a mix of bilateral contracts, over-the-counter energy sales (both physical and financial) and physical dispatches in the NYISO energy market.

ISO-NE. We receive monthly fixed transitional capacity payments for all of our 1,067 MW of ISO-NE generating capacity in accordance with the terms of the FCM settlement described below.

Approximately 70 percent of the expected energy production from our ISO-NE facilities is contracted through 2008 under bilateral agreements. This includes a portion that is price hedged under a financially-settled heat rate call-option agreement.

Regulatory Considerations

In New England, the ISO-NE is in the process of restructuring its capacity market and will be transitioning to FCM in 2010. The transitional payments for capacity commenced in December 2006, with a price of $3.05/KW-month, and gradually rise to $4.10/KW-month through June 1, 2010, when the FCM market will be fully effective. The first auction for the 2010 Period Year was held in February 2008 and capacity prices cleared at $4.50/kw month. During the transition from the pre-existing capacity markets in ISO-NE to the FCM, all listed Installed Capacity (“ICAP”) resources will receive monthly capacity payments, adjusted for each Power Year. Both of Dynegy’s facilities in ISO-NE (Bridgeport and Casco Bay) are eligible to receive the transition and FCM payments. In New York, capacity pricing is calculated as a function of NYISO’s annual required reserve margin, the estimated cost of “new entrant” generation, estimated peak demand, and the actual amount of capacity bid into the market. The NYISO has lowered the installed reserve margin for the 2007-2008 period to 16.5 percent and has targeted a 15 percent reserve margin for the 2008-2009 period.

Other

Customer Risk Management. The CRM business primarily consists of our legacy physical natural gas supply contracts, natural gas transportation contracts and power trading positions.

Interest in Development Joint Venture. Through its interest in DLS Power Development, Dynegy owns a 50 percent interest in a portfolio of greenfield development and repowering and/or expansion opportunities. The DLS Power Development portfolio is anticipated to be dynamic in nature, with changes in projects and priorities

likely to occur based on the joint venture parties’ views of market prices, supply/demand balances, contract availability and the terms thereof, environmental implications and other factors deemed relevant. The portfolio includes several projects in varying stages of development, including projects with natural gas, coal and renewable fuel types. The joint venture’s focus is on working with communities to pursue the most appropriate generation technologies.

The portfolio includes the Long Leaf project, which is designed to be a 600 MW scrubbed pulverized coal generating facility located in Georgia. During the second quarter 2007, this project received all necessary permits. In January 2008, the validity of the air pollution permit was upheld by an administrative law judge. On February 11, 2008, opponents of the project filed a petition for judicial review with the state superior court. The joint venture could seek construction financing and power purchase agreements for future generation from the facility during 2008.

Corporate. Corporate governance roles and functions, which are managed on a consolidated basis, and specialized support functions such as finance, accounting, risk control, tax, legal, human resources, administration and information technology, are included in Other in our segment reporting. Corporate general and administrative expenses, income taxes and interest expenses are also included, as are corporate-related other income and expense items. Results for Dynegy’s discontinued global communications business are also included in this segment in prior periods where appropriate.

Natural Gas Liquids. Our natural gas liquids segment consisted of our midstream asset operations, located principally in Texas, Louisiana and New Mexico, and our North American natural gas liquids marketing business, all of which we sold in October 2005. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Other Discontinued Operations—Natural Gas Liquids for further discussion.

ENVIRONMENTAL MATTERS

Our business is subject to extensive federal, state and local laws and regulations governing discharge of materials into the environment. We are committed to operating within these regulations and to conducting our business in an environmentally responsible manner. The regulatory landscape is subject to change and has become more stringent over time. Failure to acquire or maintain permits or to otherwise comply with applicable rules and regulations may result in fines and penalties or negatively impact the joint venture’s ability to advance projects in a timely manner or at all. Additionally, the process for acquiring or maintaining permits or otherwise complying with applicable rules and regulations may require unprofitable or unfavorable operating conditions or significant capital and operating expenditures.

Our aggregate expenditures (both capital and operating) for compliance with laws and regulations related to the protection of the environment were approximately $108 million in 2007 compared to approximately $60 million in 2006 and approximately $56 million in 2005. The 2007 expenditures include approximately $71 million for consent decree projects compared to $21 million for consent decree projects and $8 million for PRB coal conversion projects in 2006. We estimate that total environmental expenditures (both capital and operating) in 2008 will be approximately $235 million, including approximately $185 million for projects related to our Illinois consent decree (which is discussed below), $30 million of other environmental capital expenditures, and approximately $20 million for O&M. Changes in environmental regulations or outcomes of litigation and administrative proceedings could result in additional requirements that would necessitate increased future spending and potentially adverse operating conditions.

Global Warming

For the last several years, there has been an ongoing public debate about climate change, or global warming, and the need to reduce emissions of greenhouse gases, primarily CO₂ and methane. Power generating facilities are a major source of CO₂ emissions—in 2007, the facilities in our Midwest, West and Northeast segments

emitted approximately 25.6 million, 4.1 million and 6.6 million tons of CO₂, respectively. The adoption of regulatory programs mandating a substantial reduction in CO₂ emissions will have a far-reaching and significant impact on us and others in the power generating industry.

However, at this time, we are unable to provide an assessment of the extent of the impact that CO ₂ emission reduction programs will have on our operations and whether such programs would have a material adverse effect on our financial condition, results of operation and cash flows. While a number of programs have been proposed or are in the process of being implemented at the federal level and by various states, the timing and structure of resulting emission limits is not yet known. Emission limits could have the effect of altering the manner in which generating facilities are dispatched, and the extent to which the costs of meeting mandated emission reductions would be borne by power generators such as us or the ultimate users of electricity is unknown.

On April 2, 2007, the U. S. Supreme Court issued its decision in a case involving the regulation of CO₂ emissions of motor vehicles. The Court ruled that CO₂ is a pollutant subject to regulation under the Clean Air Act and that the U.S. Environmental Protection Agency (the “U.S. EPA”) has a duty to determine whether CO₂ emissions contribute to climate change. The U.S. EPA has not yet made any such determination, and current federal policy regarding CO₂ emissions favors voluntary reductions, increased operating efficiency and continued research and technology development. Although several bills have been introduced in Congress that would compel reductions in CO₂ emissions, it is not likely that any federal mandatory CO₂ emissions reduction program will be adopted and implemented in the immediate future, and the specific requirements of any such program cannot be predicted. However, various states in which we have generating facilities have proposed or are in the process of developing regulatory programs to limit CO₂ emissions. Officials in other states where we have generation assets have expressed the intent to regulate CO₂ emissions and we are closely following and continually analyzing legislative and regulatory developments in those jurisdictions to determine how such developments might impact our business.

Apart from any regulatory programs mandating greenhouse gases emission reductions, the issue of global warming and its effects continues to receive significant public and political attention. Consequently, Dynegy and other power generation companies that emit greenhouse gases remain subject to reputational and litigation risks attendant to their business operations.

West. Our assets in California will be subject to various state initiatives. The California Global Warming Solutions Act, which became effective on January 1, 2007, requires development of a greenhouse gas control program that will reduce the state’s greenhouse gas emissions to their 1990 levels by 2020. The program has established a statewide greenhouse gas emissions cap of 427 million metric tons beginning in 2020. Regulations to achieve required emission reductions will be due by January 2011, and implementation and enforcement of the regulatory program must be in place by January 2012. California state law also requires establishment of greenhouse gas emission performance standards for publicly owned utilities and municipalities. Proceedings have commenced to establish such performance standards restricting the rate of greenhouse gas emissions from baseload generators to that of combined-cycle natural gas baseload generation.

Northeast. Our assets in New York, Connecticut and Maine are expected to become subject to a state-driven greenhouse gas program known as RGGI as soon as 2009. RGGI is a program being developed and implemented by ten New England and Mid-Atlantic states to reduce CO₂ emissions from power plants. The participating RGGI states developed a model rule for regulating greenhouse gas using a cap-and-trade program to reduce carbon emissions by at least 10 percent of current emission levels by the year 2018.

The State of Maine’s proposed RGGI rules would implement a CO₂ cap-and-trade program, capping total authorized CO₂ emissions from affected Maine power generators beginning in 2009. Beginning in 2015, the CO₂ emission cap would be reduced each year until 2018. The proposed rules would require that each power generator hold CO₂ allowances equal to its annual CO₂ emissions. Compliance with the allowance requirement could be achieved by reducing emissions, purchasing allowances or securing offset allowances from an approved offset project. Allowances would be distributed to power generators through a state auction with the proceeds to be used for energy efficiency and other greenhouse gas reduction projects and for ratepayer relief. The rules governing the procedures and structure of the auction are still being developed.

The State of New York issued proposed RGGI rules that would also implement a cap-and-trade program capping total authorized CO₂ emissions from New York electric generators with capacity greater than 25 MW of electrical output. The initial CO₂ emissions cap for affected New York generators would start in 2009, and beginning in 2015 the cap would be reduced each year until 2018. The program would require that each affected CO₂ budget source hold CO₂ allowances equal to the total CO₂ emissions from all of its CO₂ budget units for the control period. Compliance with the allowance requirement could be achieved by reducing emissions, purchasing allowances or securing offset allowances from an approved offset project. All allowances would be distributed through an auction or auctions open to participation by any individual or entity that meets prescribed minimum financial requirements. The auction proceeds would be used to promote energy efficiency and clean energy technologies and to cover the administrative costs of the program. Although the rules governing the procedures and structure of the auction are still being developed, the intent is to conduct the first auction of CO₂ allowances in June 2008.

The State of Connecticut also enacted legislation in June 2007 that mandates a cap and trade program for CO₂, including a requirement that affected generators purchase 100 percent of the carbon credits needed to operate their facilities through an auction process. The rules governing the procedures and structure of the Connecticut auction process are still being developed.

Multi-Pollutant Air Emission Initiatives

In recent years, various federal and state legislative and regulatory multi-pollutant initiatives have been introduced. In early 2005, the U.S. EPA finalized several rules that would collectively require reductions of approximately 70 percent each in emissions of SO₂, NO_x and mercury from coal-fired power generation units by 2015 (2018 for mercury).

The Clean Air Interstate Rule (“CAIR”) is intended to reduce SO₂ and NO_x emissions across the eastern United States (29 states and the District of Columbia) and address fine particulate matter and ground-level ozone National Ambient Air Quality Standards. The rule includes both seasonal and annual NO_x control programs as well as an annual SO₂ control program. A majority of our generating facilities will be subject to these programs. The compliance deadline for Phase I for the NO_x control program is in 2009; the SO₂control program becomes effective in 2010. The final compliance phase begins in 2015. In April 2006, the U.S. EPA published a final rule that includes a federal implementation plan (“FIP”) to reduce transport of fine particulate matter and ozone. States may choose to develop their own NO_x requirements, within their respective state implementation plans, at least as stringent as the FIP, or the U.S. EPA will apply the FIP requirements to these states.

CAIR establishes a cap-and-trade program projected to reduce NO_x and SO₂ emissions by 61 percent and 73 percent, respectively, by 2018 and requires states to achieve the required reductions by adopting CAIR or developing state rules. Participation by states in the CAIR regional trading program is not mandatory. The Illinois Environmental Protection Agency has adopted a rule to implement the CAIR requirements that would require greater reductions in NO_x emissions from electric generators by setting aside 30 percent of the available NO_x emission allowances for energy efficiency and conservation projects, making those allowances unavailable to generators.

In December 2006, the Illinois Pollution Control Board approved a state rule for the control of mercury emissions from coal-fired power plants that requires additional capital and O&M expenditures at each of our Illinois coal-fired plants beginning in 2007. The State of New York has also approved a mercury rule that will likely require additional capital and operating costs. The U.S. EPA issued the Clean Air Mercury Rule (“CAMR”) for control of mercury emissions in March 2005 establishing a cap-and-trade program requiring states to promulgate rules at least as stringent as CAMR. However, on February 8, 2008 the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAMR.

The Clean Air Visibility Rule (“CAVR”) requires states to analyze and include “Best Available Retrofit Technology” (“BART”) requirements for individual facilities in their state implementation plans to address

regional haze. The state rules are due by the end of 2008 with compliance expected five years later. The requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain regulated pollutants in specific industrial categories, including utility boilers. The record for the final rule contains an analysis that demonstrates that for electric generating units subject to CAIR, CAIR will generally result in more visibility improvements than BART would provide. Therefore, it may prove sufficient for states that adopt CAIR to substitute its requirements for BART controls otherwise required by SIPs under CAVR. States are required to prepare their SIPs in tandem with the recommendation of their state environmental regional planning organizations, which may be more stringent than CAIR.

The Clean Air Act

The Clean Air Act and comparable state laws and regulations relating to air emissions impose responsibilities on owners and operators of sources of air emissions, including requirements to obtain construction and operating permits as well as compliance certifications and reporting obligations. The Clean Air Act requires that fossil-fueled plants have sufficient SO₂ and in some regions NO_X, emission allowances, as well as meet certain pollutant emission standards. Our generation facilities, some of which have changed their operations to accommodate new control equipment or changes in fuel mix, are presently in compliance with these requirements. In order to ensure continued compliance with the Clean Air Act and related rules and regulations, including ozone-related requirements, we have plans to install emission reduction technology and expect to incur total capital expenditures of up to $13 million in 2008 pursuant to such plans.

The Sandy Creek Project received its Construction Permit from the Texas Commission on Environmental Quality (“TCEQ”) in July 2006. Opponents of the project filed an appeal in the District Court which Court affirmed the decision of the TCEQ on March 29, 2007. The petitioners have further appealed the decision to the Court of Appeals. We believe that the decisions of the TCEQ and the District Court are well reasoned and expect a decision by the Court of Appeals favorable to SCEA.

In 2005, we settled a lawsuit filed by the U.S. EPA and the United States Department of Justice in the U.S. District Court for the Southern District of Illinois that alleged violations of the Clean Air Act and related federal and Illinois regulations concerning certain maintenance, repair and replacement activities at our Baldwin generating station. A consent decree was finalized in July 2005, which requires us to (i) pay a $9 million civil penalty; (ii) fund several environmental mitigation projects in the additional aggregate amount of $15 million; and (iii) install emission control equipment at our Baldwin, Vermilion, Hennepin and Havana power generating facilities. We expect our costs associated with the Midwest consent decree projects through 2012 to exceed our previously disclosed estimate of approximately $775 million. Our current estimate is $960 million, which includes approximately $90 million spent to date, please see costs per year as follows. This upward revision to our previous estimate reflects approximately $45 million in additional spend associated with the Hennepin and Havana projects, which are scheduled to be completed in 2008 and 2009, respectively. The remaining $140 million in estimated additional spend is associated with projects on the three Baldwin units, which are scheduled to be completed in 2010, 2011 and 2012, respectively, and primarily reflects the anticipated impact of current market increases in labor, material, equipment rental and related costs. Although these estimates reflect our experience to date, they include a number of assumptions and uncertainties that are beyond our control, including an assumption that labor and material costs will increase at 4 percent per year over the remaining project term. Actual future labor and material costs, as well as our overall costs associated with the Midwest consent decree projects, may vary materially from these estimates.


Projected Costs Related to Midwest Consent Decree Projects (in millions)
2008		2009		2010		2011		2012
$	185	$	250	$	215	$	170	$	50

Water Issues

Our water withdrawals and wastewater discharges are permitted under the Clean Water Act and analogous state laws. Section 316(b) of the Clean Water Act and comparable state water laws and regulations, require that the location, design, construction and capacity of cooling water intake structures reflect BTA for minimizing adverse environmental impact. The cooling water intake structures at steam generating plants are subject to this requirement. The U.S. EPA issued rules (Section 316(b) Phase II rules) in July 2004 establishing national standards aimed at protecting aquatic life at power generating facilities with existing cooling water intake structures.

On January 25, 2007, the United States Court of Appeals for the Second Circuit (the “Court”) remanded key provisions of the rules, including the U.S. EPA’s determination of BTA for existing water intake structures, to the U.S. EPA for further rulemaking. The Court’s remand of the rules to the U.S. EPA created uncertainty concerning the performance standard and the schedule for implementing the requirement. The U.S. EPA suspended its Section 316(b) Phase II Rules on July 9, 2007. In suspending the rules, the U.S. EPA advised that permit requirements for cooling water intake structures at existing facilities should be established on a case-by-case best professional judgment basis. The agency is in the process of developing a new rule implementing the requirements of Section 316(b), and the scope of requirements and the compliance methodologies allowed may become more restrictive, resulting in potentially significantly increased costs. In addition, the timing for compliance may be adjusted.

As with air quality, the requirements applicable to water quality are expected to increase in the future. A number of efforts are under way within the U.S. EPA to evaluate water quality criteria for parameters associated with the by-products of fossil fuel combustion. These parameters relate to arsenic, mercury and selenium. Significant changes in these criteria could impact discharge limits and could require our facilities to install additional water treatment equipment.

We are currently involved in an administrative proceeding in the State of New York relating to the permit governing the cooling water intake structure at our Roseton facility. If the proceeding is resolved unfavorably to us, we could be required to expend material capital or reduce plant operations. Please read Note 19—Commitments and Contingencies—Legal Proceedings—Roseton State Pollutant Discharge Elimination System Permit for further discussion of this matter.

In 2006, we successfully completed similar administrative proceedings concerning our Danskammer facility resulting in a new SPDES permit. The new Danskammer SPDES permit has been appealed and the case is pending before the New York Supreme Court, Appellate Division. We expect a decision in the case during 2008. While we cannot predict the outcome of this permit appeal, a ruling adverse to Danskammer could result in material capital expenditures or reduced plant operations. Please read Note 19—Commitments and Contingencies—Legal Proceedings—Danskammer State Pollutant Discharge Elimination System Permit for further discussion of this matter.

The NPDES permit for the water intake at our Moss Landing facility in California was recently upheld on appeal by the California Court of Appeals. The petitioners have filed a Petition for Review in the Supreme Court of California. Please read Note 19—Commitments and Contingencies—Legal Proceedings—Moss Landing National Pollutant Discharge Elimination System Permit, respectively, for further discussion of this matter.

Remedial Laws

We are subject to environmental requirements relating to handling and disposal of toxic and hazardous materials, including provisions of CERCLA and RCRA and similar state laws. CERCLA imposes strict liability on persons that contributed to the release of a “hazardous substance” into the environment. These persons include the current or previous owner and operator of a facility and companies that disposed, or arranged for disposal, of hazardous substances found at a contaminated facility. CERCLA also authorizes the U.S. EPA and, in some

cases, private parties to take actions in response to threats to public health or the environment and to seek recovery for costs of cleaning up hazardous substances that have been released and for damages to natural resources from responsible parties. Further, it is not uncommon for neighboring landowners and other affected parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. CERCLA or RCRA could impose remedial obligations at a variety of our facilities.

Additionally, the U.S. EPA may develop new regulations that impose additional requirements on facilities that store or dispose of non-hazardous fossil fuel combustion materials, including coal ash. If so, we and other similarly situated power generators may be required to change current waste management practices and incur additional capital expenditures to comply with these regulations.

As a result of their age, a number of our facilities contain quantities of asbestos-containing materials, lead-based paint, and/or other regulated materials. Existing state and federal rules require the proper management and disposal of these materials. We have developed a management plan that includes proper maintenance of existing non-friable asbestos installations and removal and abatement of asbestos-containing materials where necessary because of maintenance, repairs, replacement or damage to the asbestos itself. Please read Note 2—Summary of Significant Accounting Policies—Asset Retirement Obligations for further discussion of the liabilities recorded in 2005 for the costs of future removal of asbestos containing materials from certain of our power generation facilities.

COMPETITION

Demand for power may be met by generation capacity based on several competing generation technologies, such as natural gas-fired, coal-fired or nuclear generation, as well as power generating facilities fueled by alternative energy sources, including hydro power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Our power generation businesses in the Midwest, West and Northeast compete with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, other energy service companies and financial institutions. We believe that our ability to compete effectively in these businesses will be driven in large part by our ability to achieve and maintain a low cost of production, primarily by managing fuel costs, and to provide reliable service to our customers. Our ability to compete effectively will also be impacted by various governmental and regulatory activities designed to support the construction and operation of renewables-fueled power generation facilities. We believe our primary competitors consist of at least 20 companies in the power generation business.

OPERATIONAL RISKS AND INSURANCE

We are subject to all risks inherent in the power generation business. These risks include, but are not limited to, equipment breakdowns or malfunctions, explosions, fires, terrorist attacks, product spillage, weather including hurricanes and tornados, nature including earthquakes and inadequate maintenance of rights-of-way, which could result in damage to or destruction of operating assets and other property, or could result in personal injury, loss of life or pollution of the environment, as well as curtailment or suspension of operations at the affected facility. We maintain general public liability, property/boiler and machinery, and business interruption insurance in amounts that we consider to be appropriate for such risks. Such insurance is subject to deductibles and caps that we consider reasonable and not excessive given the current insurance market environment. The costs associated with these insurance coverages have been volatile during recent periods, and may continue to be so in the future. The occurrence of a significant event not fully insured or indemnified against by a third party, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. While we currently maintain levels and types of insurance that we believe to be prudent under current insurance industry market conditions, our potential inability to secure these levels and types of insurance in the future could negatively impact our business operations and financial stability, particularly if an uninsured loss were to occur. No assurance can be given that we will be able to maintain these levels of insurance in the future at rates we consider commercially reasonable.

We also face market, price, credit and other risks relative to our business. Please read Item 7A. Quantitative and Qualitative Disclosures About Market Risk for further discussion of these risks.

In addition to these operational risks, we also face the risk of damage to our reputation and financial loss as a result of inadequate or failed internal processes and systems. A systems failure or failure to enter a transaction properly into our records and systems may result in an inability to settle a transaction in a timely manner or cause a contract breach. Our inability to implement the policies and procedures that we have developed to minimize these risks could increase our potential exposure to damage to our reputation and to financial loss. Please read Item 9A. Controls and Procedures for further discussion of our internal control systems.

SIGNIFICANT CUSTOMERS

For the year ended December 31, 2007, approximately 23 percent, 17 percent and 11 percent of our consolidated revenues were derived from transactions with MISO, NYISO and Ameren, respectively. For the year ended December 31, 2006, approximately 23 percent, 19 percent and 18 percent of our consolidated revenues were derived from transactions with Ameren, MISO and NYISO, respectively. For the year ended December 31, 2005, approximately 26 percent and 20 percent of our consolidated revenues were derived from transactions with NYISO and Ameren, respectively. No other customer accounted for more than 10 percent of our consolidated revenues during 2007, 2006 or 2005.

EMPLOYEES

At December 31, 2007, we had approximately 500 employees at our administrative offices and approximately 1,300 employees at our operating facilities. Approximately 700 employees at Dynegy-operated facilities are subject to collective bargaining agreements with various unions that expire in March 2008 (as amended), August 2010 and June 2011. We believe relations with our employees are satisfactory.

Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS

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

•

beliefs about commodity pricing and generation volumes;

•

sufficiency of and access to coal, fuel oil and natural gas inventories and transportation, including strategies to deploy coal supplies;

•

beliefs and assumptions about market competition, fuel supply, generation capacity and regional supply and demand characteristics of the wholesale power generation market;

•

strategies to capture opportunities presented by rising commodity prices and strategies to manage our exposure to energy price volatility;

•

beliefs and assumptions about weather, economic conditions and the demand for electricity;

•

our ability to compete effectively with industry participants;

•

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

•

strategies to address our substantial leverage or to access the capital markets;

•

beliefs and assumptions relating to liquidity;

•

beliefs and expectations regarding financing, development and timing of any and all joint venture projects;

•

anticipated benefits of diversifying our operations;

•

expectations regarding capital expenditures, interest expense and other payments;

•

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

•

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

•

expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations, including those relating to global warming;

•

expectations and estimates regarding the Midwest consent decree and the associated costs; and

•

efforts to position our power generation business for future growth and pursuing and executing acquisition, disposition or combination opportunities.

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

FACTORS THAT MAY AFFECT FUTURE RESULTS

Risks Related to the Operations of Our Business

We do not fully contract our future sales potential and therefore are exposed to commodity prices risk associated with changes in prices of power, natural gas, coal and oil. To the extent we do engage in forward sales activities, our models representing the market may be inaccurate.

Since a substantial portion of our production capacity may not be sold through power purchase agreements and is thus subject to commodity price risks, we have the potential to receive higher or lower prices for electric energy, capacity and ancillary services resulting in volatile revenue and cash flow. To the extent that our generated power is not subject to a power purchase agreement or similar arrangement, we generally will pursue sales of such generated power based on current market prices. Where forward sales are not executed, we will be impacted by changes in commodity prices, and, in an environment where fuel costs increase and power prices decrease, our financial condition, results of operations and cash flows may be materially adversely affected. In those instances where we do execute forward sales or related financial transactions, our internal models may not accurately represent the markets in which we participate, potentially causing us to make less favorable decisions, which could have a negative impact on our financial condition, results of operations and cash flows, or result in an inability to capture market upside opportunities presented by rising prices. Additionally, we utilize mark-to-market accounting for certain of our forward sales and related financial transactions, which may cause earnings variability.

Because most of our power generation facilities operate mostly without term power sales agreements and because wholesale power prices are subject to significant volatility, our revenues and profitability are subject to significant fluctuations.

Most of our facilities operate as “merchant” facilities without term power sales agreements. Without term power sales agreements, we cannot be sure that we will be able to sell any or all of the electric energy, capacity or ancillary services from our facilities at commercially attractive rates or that our facilities will be able to operate profitably. This could lead to decreased financial results as well as future impairments of our property, plant and equipment or to the retirement of certain of our facilities resulting in economic losses and liabilities.

Because we largely sell electric energy, capacity and ancillary services into the wholesale energy spot market or into other power markets on a term basis, we are not guaranteed any rate of return on our capital investments. Rather, our financial condition, results of operations and cash flows are likely to depend, in large part, upon prevailing market prices for power and the fuel to generate such power. Wholesale power markets are subject to significant price fluctuations over relatively short periods of time and can be unpredictable.

Given the volatility of power commodity prices, to the extent we do not secure term power sales agreements for the output of our power generation facilities, our revenues and profitability will be subject to increased volatility, and our financial condition, results of operations and cash flows could be materially adversely affected.

We are exposed to the risk of fuel and fuel transportation cost increases and interruptions in fuel supplies because some of our facilities do not have long-term coal, natural gas or fuel oil supply agreements.

Many of our power generation facilities, specifically those that are natural gas-fired, purchase their fuel requirements under short-term contracts or on the spot market. As a result, we face the risks of supply interruptions and fuel price volatility, as fuel deliveries may not exactly match that required for energy sales, due in part to our need to pre-purchase fuel inventories for reliability and dispatch requirements.

Moreover, operation of many of our coal-fired generation facilities is highly dependent on our ability to procure coal. Power generators in the Midwest and the Northeast have experienced significant pressures on available coal supplies that are either transportation or supply related. In particular, transportation of South

American coal, which we use for our Northeastern coal assets, is subject to local political and other factors that could have a negative impact on our coal deliveries. If we are unable to procure fuel for physical delivery at prices we consider favorable, or if we experience transportation delays or disruptions, our financial condition, results of operations and cash flows could be materially adversely affected.

Our costs for compliance with existing environmental laws are significant, and costs for compliance with new environmental laws could adversely affect our financial condition, results of operations and cash flows.

Our business is subject to extensive and frequently changing environmental regulation by federal, state and local authorities. Such environmental regulation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. Existing environmental laws and regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, litigation or regulatory or enforcement proceedings could be commenced and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions. Proposals currently under consideration could, if and when adopted or enacted, require us to make substantial capital and operating expenditures. If any of these events occur, our financial condition, results of operations and cash flows could be materially adversely affected.

Moreover, many environmental laws require approvals or permits from governmental authorities for the operation of a power generation facility, before construction or modification of a project may commence or before wastes or other materials may be discharged into the environment. The process for obtaining necessary permits can be lengthy and complex and can sometimes result in the establishment of permit conditions that make the project or activity for which the permit was sought unprofitable or otherwise unattractive. Even where permits are not required, compliance with environmental laws and regulations can require significant capital and operating expenditures. We are required to comply with numerous environmental laws and regulations, and to obtain numerous governmental permits when we construct, modify and operate our facilities. In addition, certain of our facilities are also required to comply with the terms of consent decrees or other governmental orders.

With the continuing trend toward stricter standards, greater regulation and more extensive permitting requirements, our capital and operating environmental expenditures are likely to be substantial and may increase in the future. We may not be able to obtain or maintain all required environmental regulatory permits or other approvals that we need to operate our business. If there is a delay in obtaining any required environmental regulatory approvals or permits, or if we fail to obtain or comply with any required approval or permit, the operation of our facilities may be interrupted or become subject to additional costs and, as a result, our financial condition, results of operations and cash flows could be materially adversely affected.

Our business is subject to complex government regulation. Changes in these regulations or in their implementation may affect costs of operating our facilities or our ability to operate our facilities, or increase competition, any of which would negatively impact our results of operations.

We are subject to extensive federal, state and local laws and regulations governing the generation and sale of energy commodities, as well as discharge of materials into the environment and otherwise relating to the environment and public health and safety in each of the jurisdictions in which we have operations. Compliance with these laws and regulations requires expenses (including legal representation) and monitoring, capital and operating expenditures, including those related to pollution control equipment, emission credits, remediation obligations and permitting at various operating facilities. Furthermore, these regulations are subject to change at any time, and we cannot predict what changes may occur in the future or how such changes might affect any facet of our business.

The costs and burdens associated with complying with the increased number of regulations may have a material adverse effect on us, if we fail to comply with the laws and regulations governing our business or if we

fail to maintain or obtain advantageous regulatory authorizations and exemptions. Moreover, increased competition resulting from potential legislative changes, regulatory changes or other factors may create greater risks to the stability of our power generation earnings and cash flows generally. In addition, we are subject to the risk of litigation relating to existing and potential legal, regulatory, administrative and legislative requirements and the activities they govern, including litigation involving greenhouse gases and other emissions from our power generation facilities.

Availability and cost of emission credits could materially impact our costs of operations.

We are required to maintain, either by allocation or purchase, sufficient emission credits to support our operations in the ordinary course of operating our power generation facilities. These credits are used to meet our obligations imposed by various applicable environmental laws, with respect to which the trend toward more stringent regulations (including regulations currently proposed or being discussed regarding carbon emissions) will likely require us to obtain new or additional emission credits. If our operational needs require more than our allocated allowances of emission credits, we may be forced to purchase such credits on the open market, which could be costly. If we are unable to maintain sufficient emission credits to match our operational needs, we may have to curtail our operations so as not to exceed our available emission credits, or install costly new emissions controls. As we use the emissions credits that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such credits are available for purchase, but only at significantly higher prices, the purchase of such credits could materially increase our costs of operations in the affected markets.

Competition in wholesale power markets, together with an oversupply of power generation capacity in certain regional markets, may have a material adverse effect on our financial condition, results of operations and cash flows.

We have numerous competitors and additional competitors may enter the industry. Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities and other energy service companies in the sale of energy, capacity and ancillary services, as well as in the procurement of fuel, transmission and transportation services. Moreover, aggregate demand for power may be met by generation capacity based on several competing technologies, as well as power generating facilities fueled by alternative or renewable energy sources, including hydroelectric power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Regulatory initiatives designed to enhance renewable generation could increase competition from these types of facilities. In addition, a buildup of new electric generation facilities in recent years has resulted in an abundance of power generation capacity in certain regional markets we serve.

We also compete against other energy merchants on the basis of our relative operating skills, financial position and access to credit sources. Energy customers, wholesale energy suppliers and transporters often seek financial guarantees, credit support such as letters of credit, and other assurances that their energy contracts will be satisfied. Companies with which we compete may have greater resources in these areas. In addition, many of our current facilities are relatively old. Newer plants owned by competitors will often be more efficient than some of our plants, which may put some of our plants at a competitive disadvantage. Over time, some of our plants may become obsolete in their markets, or be unable to compete, because of the construction of new, more efficient plants.

Other factors may contribute to increased competition in wholesale power markets. New forms of capital and competitors have entered the industry in the last several years, including financial investors who perceive that asset values are at levels below their true replacement value. As a result, a number of generation facilities in the United States are now owned by lenders and investment companies. Furthermore, mergers and asset reallocations in the industry could create powerful new competitors. Under any scenario, we anticipate that we will face competition from numerous companies in the industry, some of which have superior capital structures.

Moreover, many companies in the regulated utility industry, with which the wholesale power industry is closely linked, are also restructuring or reviewing their strategies. Several of those companies have discontinued or are discontinuing their unregulated activities and seeking to divest or spin-off their unregulated subsidiaries. Some of those companies have had, or are attempting to have, their regulated subsidiaries acquire assets out of their or other companies’ unregulated subsidiaries. This may lead to increased competition between the regulated utilities and the unregulated power producers within certain markets. To the extent that competition increases, our financial condition, results of operations and cash flows may be materially adversely affected.

We do not own or control transmission facilities required to sell the wholesale power from our generation facilities. If the transmission service is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. Furthermore, these transmission facilities are operated by RTOs and ISOs, which are subject to changes in structure and operation and impose various pricing limitations. These changes and pricing limitations may affect our ability to deliver power to the market that would, in turn, adversely affect the profitability of our generation facilities.

We do not own or control the transmission facilities required to sell the wholesale power from our generation facilities. If the transmission service from these facilities is unavailable or disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. RTOs and ISOs provide transmission services, administer transparent and competitive power markets and maintain system reliability. Many of these RTOs and ISOs operate in the real-time and day-ahead markets in which we sell energy. The RTOs and ISOs that oversee most of the wholesale power markets impose, and in the future may continue to impose, offer caps and other mechanisms to guard against the potential exercise of market power in these markets as well as price limitations. These types of price limitations and other regulatory mechanisms may adversely affect the profitability of our generation facilities that sell energy and capacity into the wholesale power markets. Problems or delays that may arise in the formation and operation of new or maturing RTOs and similar market structures, or changes in geographic scope, rules or market operations of existing RTOs, may also affect our ability to sell, the prices we receive or the cost to transmit power produced by our generating facilities. Rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. Furthermore, the rates for transmission capacity from these facilities are set by others and thus are subject to changes, some of which could be significant, and as a result, our financial condition, results of operations and cash flows may be materially adversely affected.

Plum Point and Sandy Creek, which are currently under construction, may not be completed, and the construction of other development projects in which Dynegy has an interest via DLS Power Holdings and DLS Power Development may never be initiated or completed.

We possess ownership interests in Plum Point and Sandy Creek, which are currently in the construction phase, with expected completion dates in 2010 and 2012, respectively. Dynegy also possesses a 50 percent ownership interest in DLS Power Holdings and DLS Power Development, which is in the process of developing various “greenfield” projects and expansion and replacement projects. Additional development projects may be contributed to DLS Power Holdings and DLS Power Development from time to time by Dynegy and the LS Power Group.

These projects generally require various governmental and other approvals, which may not be received. As a result of economic and other conditions, Plum Point and Sandy Creek may not be completed, and the development projects may not be pursued or completed, and higher costs than those that are anticipated may be incurred with respect to any of the projects.

In addition, the development and construction of power generation facilities may be adversely affected by one or more factors commonly associated with large infrastructure projects, including, but not limited to, changes in the forecasted financial viability of new-build generation in a region, shortages of equipment, materials and

labor, long-term contracting opportunities, delays in delivery of equipment and materials, labor disputes, litigation, failure to obtain necessary governmental and regulatory approvals and permits, adverse weather conditions, unanticipated increases in costs, natural disasters, accidents, local and political opposition, unforeseen engineering, design, environmental or geological problems and other unforeseen events or circumstances. Any one of these events could result in delays in, or even the abandonment of, the development of the affected power generation facility. Such events may also result in cost overruns, payments under committed contracts associated with the affected project, and/or the write-off of equity investment in the project. Any such development may materially and adversely affect our financial condition, results of operations and cash flows.

Our financial condition, results of operations and cash flows would be adversely impacted by strikes or work stoppages by our unionized employees.

A majority of the employees at our facilities are subject to collective bargaining agreements with various unions that expire from 2008 through 2011. If union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, we could experience reduced power generation or outages if replacement labor is not procured. The ability to procure such replacement labor is uncertain. Strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms could have a material adverse effect on our financial condition, results of operations and cash flows.

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

An event of loss and certain other events relating to our Roseton and Danskammer power generation facilities could trigger a substantial obligation that would be difficult for us to satisfy.

We acquired the Roseton and Danskammer power generation facilities in January 2001. In May 2001, we entered into an asset-backed sale-leaseback transaction relating to these facilities to provide us with long-term acquisition financing. In this transaction, we sold four of the six generating units comprising these facilities for approximately $920 million to Danskammer OL LLC and Roseton OL LLC, and we concurrently agreed to lease them back from these entities. We have no option to purchase the leased facilities at Roseton or Danskammer at the end of their lease terms, which end in 2035 and 2031, respectively. If one or more of the leases were to be terminated prior to the end of its term because of an event of loss (such as substantial damage to a facility or a condemnation or similar governmental taking or action), because it becomes illegal for us to comply with the lease, or because a change in law makes the facility economically or technologically obsolete, we would be required to make a termination payment in an amount sufficient to compensate the lessor for termination of the lease, including redeeming the pass-through trust certificates related to the unit or facility for which the lease is terminated. As of December 31, 2007, the termination payment would be approximately $1 billion for the Roseton and Danskammer power generation facilities. It could be difficult for us to raise sufficient funds to make this termination payment if a termination of this type were to occur with respect to the Roseton and Danskammer power generation facilities, resulting in a material adverse effect on our financial condition, results of operations and cash flows.

We have significant debt that could negatively impact our business.

We have and will continue to have a significant amount of debt outstanding. As of December 31, 2007, we had total consolidated debt of approximately $6.0 billion. Our significant level of debt could:

•

make it difficult to satisfy our financial obligations;

•

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

•

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

•

impact the evaluation of our creditworthiness by counterparties to commercial agreements and affect the level of collateral we are required to post under such agreements;

•

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

•

make it difficult or impossible for us to make acquisitions that would help our business or allow us to remain competitive; and

•

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

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

Covenants in our financing agreements impose significant restrictions on us. The terms of our debt may severely limit our ability to plan for or respond to changes in our businesses, and the failure to comply with these covenants could lead the lenders to foreclose on, and acquire control of, substantially all of our assets, which would have a material adverse impact on our business, financial condition, results of operations and cash flows.

Our financing agreements, including the Fifth Amended and Restated Credit Facility, have terms that restrict our ability to take specific actions in planning for and responding to changes in our business without the consent of the lenders, even if such actions may be in our best interest. The agreements governing our debt obligations require us to meet specific financial tests both as a matter of course and as a precondition to the incurrence of additional debt and to the making of restricted payments, among other things. They also limit our ability to return capital to our stockholders. Any additional long-term debt that we may enter into in the future may also contain similar restrictions.

Our ability to comply with the financial tests and other covenants in our financing agreements, as they currently exist or as they may be amended, may be affected by many events beyond our control, and our future operating results may not allow us to comply with the covenants or, in the event of a default, to remedy that default. Our failure to comply with those financial covenants or to comply with the other restrictions in our financing agreements could result in a default, causing our debt obligations under such financing agreements (and by reason of cross-default or cross-acceleration provisions, our other indebtedness) to become immediately due and payable, which could have a material adverse impact on our business, financial condition, results of operations or cash flows. If those lenders accelerate the payment of such indebtedness, we cannot assure you that we could pay-off or refinance that indebtedness immediately and continue to operate our business. If we are unable to repay those amounts, otherwise cure the default, or obtain replacement financing, the holders of the indebtedness under our secured debt obligations would be entitled to foreclose on, and acquire control of substantially all of our assets, which would have a material adverse impact on our financial condition, results of operations and cash flows.

Our access to the capital markets may be limited.

We may require additional capital from time to time beyond the near-term. Unlike those companies in the power generation industry that are “investment grade” and for which the capital markets are typically open, our access to the capital markets may be limited. Moreover, 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. Our ability to obtain capital and the costs of such capital are dependent on numerous factors, including:

•

general economic and capital market conditions;

•

covenants in our existing debt and credit agreements;

•

credit availability from banks and other financial institutions;

•

investor confidence in us and the regional wholesale power markets;

•

our financial performance and the financial performance of our subsidiaries;

•

our levels of debt;

•

our requirements for posting collateral under various commercial agreements;

•

our maintenance of acceptable credit ratings;

•

our cash flow;

•

provisions of tax and securities laws that may impact raising capital;

•

financing policies of banking institutions related to investing in plants which will emit greenhouse gasses; and

•

our long-term business prospects.

We may not be successful in obtaining additional capital for these or other reasons. An inability to access capital may limit our ability to pursue development projects, plant improvements or acquisitions that we may rely on for future growth and to comply with regulatory requirements and, as a result, may have a material adverse effect on our financial condition, results of operations and cash flows, and on our ability to execute our business strategy.

We expect that our non-investment grade status will continue to adversely affect our financial condition, results of operations and cash flows. We may not have adequate liquidity to post required amounts of additional collateral.

Our credit ratings are currently below investment grade. Our current non-investment grade ratings increase our borrowing costs, both by increasing the actual interest rates we are required to pay under any existing debt (to the extent it is linked to our credit rating) and any debt in the capital markets that we are able to issue. We cannot assure you that our credit ratings will improve, or that they will not decline, in the future.

Additionally, our non-investment grade status limits our ability to refinance our debt obligations and to access the capital markets. Should our ratings continue at their current levels, or should our ratings be further downgraded, we would expect these negative effects to continue and, in the case of a downgrade, become more pronounced.

Our credit ratings also require us to either prepay obligations or post significant amounts of collateral to support our business. Various commodity trading counterparties make collateral demands that reflect our non-investment grade credit ratings, the counterparties’ views of our creditworthiness, as well as changes in commodity prices. We use a portion of our capital resources, in the form of cash and letters of credit, to satisfy these counterparty collateral demands. Our commodity agreements contain requirements to post additional collateral under certain circumstances. If conditions change such that counterparties are entitled to demand such additional collateral, our liquidity could be severely strained and may have a material adverse effect on our financial condition, results of operations and cash flows. Factors that could trigger increased demands for collateral include additional adverse changes in our industry, negative regulatory or litigation developments, adverse events affecting us, changes in our credit rating or liquidity and changes in commodity prices for power and fuel. In addition, to the extent we engage in forward sales against volatility in commodity prices and, as a result, our cash flow is less than anticipated, a source of our liquidity resources may be depleted.

We conduct a substantial portion of our operations through our subsidiaries and may be limited in our ability to access funds from these subsidiaries to service our debt.

We conduct a substantial portion of our operations through our subsidiaries and depend to a large degree upon dividends and other intercompany transfers of funds from our subsidiaries to meet our debt service and other obligations. In addition, the ability of our subsidiaries to pay dividends and make other payments to us may be restricted by, among other things, applicable corporate and other laws, potentially adverse tax consequences and agreements of our subsidiaries. If we are unable to access the cash flow of our subsidiaries, we may have difficulty meeting our debt obligations.

Risks Related to Investing

Our growth strategy may include acquisitions or combinations that could fail or present unanticipated problems for our business in the future, which would adversely affect our ability to realize the anticipated benefits of those transactions.

Our growth strategy may include acquiring or combining with other businesses. We may not be able to identify suitable acquisition or combination opportunities or finance and complete any particular acquisition or combination successfully. Furthermore, acquisitions and combinations involve a number of risks and challenges, including:

•

diversion of our management’s attention;

•

the ability to obtain required regulatory and other approvals;

•

the need to integrate acquired or combined operations with our operations;

•

potential loss of key employees;

•

difficulty in evaluating the power assets, operating costs, infrastructure requirements, environmental and other liabilities and other factors beyond our control;

•

potential lack of operating experience in new geographic/power markets or with different fuel sources;

•

an increase in our expenses and working capital requirements; and

•

the possibility that we may be required to issue a substantial amount of additional equity or debt securities or assume additional debt in connection with any such transactions.

Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows or realize synergies or other anticipated benefits from a strategic transaction. Furthermore, the market for transactions is highly competitive, which may adversely affect our ability to find transactions that fit our strategic objectives or increase the price we are required to pay (which could decrease the benefit of the transaction or hinder our desire or ability to consummate the transaction). In pursuing our strategy, consistent with industry practice, we routinely engage in discussions with industry participants regarding potential transactions, large and small. We intend to continue to engage in strategic discussions and will need to respond to potential opportunities quickly and decisively. As a result, strategic transactions may occur at any time and may be significant in size relative to our assets and operations.

If our goodwill or amortizable intangible assets become impaired, we may be required to record a significant charge to earnings.

We have significant intangible assets and goodwill recorded on our balance sheet. In accordance with GAAP, we review our intangible assets for impairment when events or changes in circumstances indicate the carrying value may not be recoverable. Goodwill is required to be tested for impairment at least annually. Factors that may be considered a change in circumstances indicating that the carrying value of our goodwill or intangible assets may not be recoverable include a decline in future cash flows and slower growth rates in the energy industry. If we determine an impairment of our goodwill or intangible assets is necessary, we would be required to record a charge to earnings in our financial statements, which could be significant.

The interests of the LS Control Group may conflict with your interests and, with respect to DLS Power Holdings and DLS Power Development, Dynegy’s interests.

The LS Control Group (as defined below) owns approximately 40 percent of Dynegy’s voting power and has the right to nominate up to three members of Dynegy’s 11-member board of directors. By virtue of such stock ownership and board representation, the LS Control Group has, as described in the risk factor immediately below, the power to influence Dynegy’s affairs and the outcome of matters required to be submitted to Dynegy’s stockholders for approval. Moreover, by virtue of such stock ownership and board representation and its

50 percent membership interest (via LS Associates) in DLS Power Holdings and DLS Power Development, the LS Control Group has the power to influence the affairs of DLS Power Holdings and DLS Power Development.

The LS Control Group may have interests that differ from those of holders of Dynegy’s Class A common stock, and these relationships could give rise to conflicts of interest, including:

•

conflicts between the LS Control Group and Dynegy’s other stockholders, whose interests may differ with respect to the strategic direction or significant corporate transactions of the company; and

•

conflicts related to corporate opportunities that could be pursued by Dynegy, on the one hand, or by the LS Control Group, on the other hand.

Further, Dynegy’s amended and restated certificate of incorporation renounces any interest in, and waives, any claim that a corporate or business opportunity taken by the LS Control Group constitutes a corporate opportunity of the company, unless such corporate or business opportunity is expressly offered to one of Dynegy’s directors or officers.

The LS Control Group’s significant interest in Dynegy could be determinative in matters submitted to a vote by Dynegy’s stockholders. In addition, the rights granted to the LS Shareholders (as defined below) under the Shareholder Agreement (as defined below) and Dynegy’s amended and restated bylaws provide them significant influence over Dynegy. Such influence could result in Dynegy either taking actions that Dynegy’s other stockholders do not support or failing to take actions that Dynegy’s other stockholders do support.

The LS Control Group’s ownership interest in Dynegy, together with its rights under the Shareholder Agreement and Dynegy’s amended and restated bylaws, provides it with significant influence over the conduct of Dynegy’s business. Given the LS Control Group’s significant interest in Dynegy, it may have the power to determine the outcome of matters submitted to a vote of all of Dynegy’s stockholders.

Rights granted to the LS Control Group under the Shareholder Agreement and Dynegy’s amended and restated bylaws that provide it with significant influence over Dynegy’s business include:

•

the ability to nominate up to three directors to Dynegy’s board of directors based on its percentage ownership interest in Dynegy; and

•

the requirement that Dynegy not pursue any of the following actions if all directors nominated by the LS Control Group present at the relevant board meeting vote against such action:

•

any amendment of Dynegy’s amended and restated certificate of incorporation or amended and restated bylaws;

•

any merger or consolidation of Dynegy and certain dispositions of Dynegy’s assets or businesses, certain acquisitions, binding capital commitments, guarantees and investments and certain joint ventures with an aggregate value in excess of a specified amount;

•

Dynegy’s payment of dividends or similar distributions;

•

Dynegy’s engagement in new lines of business;

•

Dynegy’s liquidation or dissolution, or certain bankruptcy-related events with respect to Dynegy;

•

Dynegy’s issuance of any equity securities, with certain exceptions for issuances of Dynegy’s Class A common stock;

•

Dynegy’s incurrence of any indebtedness in excess of a specified amount;

•

the hiring, or termination of the employment of, Dynegy’s Chief Executive Officer (other than Bruce A. Williamson);

•

our entry into any agreement or other action that limits the activities of any holder of Dynegy’s Class B common stock or any of such holder’s affiliates; and

•

our entry into other material transactions with a value in excess of a specified amount.

Such influence could result in us either taking actions that Dynegy’s other stockholders do not support or failing to take actions that Dynegy’s other stockholders do support.

Dynegy’s stockholders may be adversely affected by the expiration of the transfer restrictions in the Shareholder Agreement, which would enable the LS Control Group to, among other things, transfer a significant percentage of Dynegy’s common stock to a third party.

The transfer provisions in the Shareholder Agreement, subject to specified exceptions, restrict the LS Control Group from transferring shares of Dynegy’s common stock. Subject to specified exceptions, the LS Control Group is prohibited from transferring shares of Dynegy’s common stock until the earlier of:

•

April 2, 2009;

•

the date the stockholders party to the Shareholder Agreement cease to own at least 15 percent of the total combined voting power of Dynegy’s outstanding securities; or

•

subject to certain conditions, the date a third party offer is made to acquire more than 25 percent of Dynegy’s assets or voting securities.

In addition, if the transfer restrictions in the Shareholder Agreement are terminated, the LS Control Group will be free to sell their shares of Dynegy’s common stock, subject to certain exceptions, to any person on the open market, in privately negotiated transactions or otherwise in accordance with law. These sales or transfers, as well as sales or other dispositions, could create a substantial decline in the price of shares of Dynegy’s common stock, including Dynegy’s Class A common stock.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 2. Properties

We have included descriptions of the location and general character of our principal physical operating properties by segment in “Item 1. Business” for further discussion, which is incorporated herein by reference. Substantially all of our assets, including the power generation facilities we own, are pledged as collateral to secure the repayment of, and our other obligations under, the Fifth Amended and Restated Credit Facility. Please read Note 15—Debt for further discussion.

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

Item 3. Legal Proceedings

Please read Note 19—Commitments and Contingencies—Legal Proceedings for a description of our material legal proceedings, which is incorporated herein by reference.

Item 4. Submission of Matters to a Vote of Security Holders

Dynegy. No matter was submitted to a vote of Dynegy’s security holders during the fourth quarter 2007.

DHI. Omitted pursuant to General Instruction (I)(2)(c) of Form 10-K.

PART II

Item 5.

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

Dynegy

Dynegy’s Class A common stock, $0.01 par value per share, is listed and traded on the New York Stock Exchange under the ticker symbol “DYN”. The number of stockholders of record of its Class A common stock as of February 21, 2008, based upon records of registered holders maintained by its transfer agent, was 24,246.

Dynegy’s Class B common stock, $0.01 par value per share, is neither listed nor traded on any exchange. All of the shares of Class B common stock are owned by the LS Control Group (as defined below).

The following table sets forth the high and low closing sales prices for the Class A common stock for each full quarterly period during the fiscal years ended December 31, 2007 and 2006 and during the elapsed portion of Dynegy’s first fiscal quarter of 2008 prior to the filing of this Form 10-K, as reported on the New York Stock Exchange Composite Tape.

Summary of Dynegy’s Common Stock Price


	High		Low
2008:
First Quarter (through February 21, 2008)	$	8.11	$	6.44
2007:
Fourth Quarter	$	9.50	$	7.14
Third Quarter		10.62		7.86
Second Quarter		10.65		9.08
First Quarter		9.58		6.52
2006:
Fourth Quarter	$	7.24	$	5.36
Third Quarter		6.34		5.09
Second Quarter		5.47		4.68
First Quarter		5.72		4.72

During the fiscal years ended December 31, 2007 and 2006, Dynegy’s Board of Directors did not elect to pay a common stock dividend. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Dividends on Dynegy Common Stock” for further discussion of its dividend policy. Any decision to pay a dividend will be at the discretion of Dynegy’s Board of Directors, and subject to the terms of its then-outstanding indebtedness, but Dynegy does not expect to pay a common stock dividend in the foreseeable future. Dynegy has not paid a dividend on any class of its common stock since 2002. Please read Note 20—Capital Stock—Common Stock for further discussion.

Shareholder Agreement. Dynegy entered into a Shareholder Agreement dated as of September 14, 2006 with the LS Entities (the “Shareholder Agreement”) that, among other things, limits the LS Contributing Entities’ ownership of Dynegy’s common stock and restricts the manner in which the LS Entities may transfer their shares of Class B common stock. The LS Contributing Entities and their permitted transferees, affiliates and associates, (the “LS Control Group”) together with Luminus Management LLC and its affiliates, (“Luminus”) may not acquire any of Dynegy’s equity securities if, after giving effect to such acquisition, they would own more than approximately 40 percent of the total outstanding shares of Dynegy’s common stock. If the LS Control Group owns less than 30 percent of the total outstanding shares of Dynegy’s common stock, Luminus may acquire Dynegy’s equity securities if, after such acquisition, Luminus would not own more than 5 percent of the total outstanding shares of Dynegy’s common stock.

In addition, after the expiration of the earlier of (i) two years from the Merger, (ii) the date the LS Entities cease to collectively own 15 percent of Dynegy’s outstanding voting securities and (iii) the occurrence of certain third party offers to acquire more than 25 percent of Dynegy, (the “Lock-Up Period”) the LS Entities may make an offer to purchase all of the outstanding shares of Dynegy’s common stock. Upon such offer, Dynegy may either accept the offer or conduct an auction in which the LS Entities may elect, at their option, whether or not to participate. The LS Entities have the right to top the winning offer at 105 percent of the offer price in any auction in which they elect not to participate.

The Shareholder Agreement also (i) provides that if the LS Entities or the Class B common stock directors block certain sale transactions with respect to Dynegy more than twice in any 18 month period, Dynegy’s Board can cause an auction for the sale of Dynegy, (ii) prohibits Dynegy from issuing Class B common stock to any person other than the LS Entities and (iii) provides the LS Entities with certain preemptive rights to acquire shares of Dynegy’s common stock in proportion to their then-existing ownership of our common stock whenever we issue shares of stock or securities convertible into Dynegy’s common stock.

Generally, until the expiration of the Lock-Up Period, the LS Control Group may not transfer their shares, provided that, (i) beginning September 29, 2007 (that is, 180 days after the Merger), the LS Control Group may distribute their shares to their permitted transferees; provided that Dynegy may block such distribution for up to 60 days per calendar year in connection with a proposed underwritten public offering; (ii) during the period that began on September 29, 2007 and ends on March 26, 2008, 21,250,000 shares of Class B common stock may be transferred in widely dispersed sales, provided that to the extent such number of shares is not transferred during any such 180-day period, any unused amount may be carried forward to the next succeeding 180-day period (but in no event may more than 42,500,000 share of Class B common stock be transferred during any 180-day period), and (iii) after expiration of the Lock-Up Period, the LS Control Group may freely transfer their shares of Class B common stock to any person so long as such transfer would not result in such person, together with such person’s affiliates and associates, owning more than 15 percent of shares of Dynegy’s common stock. All shares of Class B common stock transferred to any person that is a member of the LS Control Group will automatically be converted into shares of Class A common stock.

LS Registration Rights Agreement. In connection with the Merger, Dynegy entered into a Registration Rights Agreement dated September 14, 2006, (“LS Registration Rights Agreement”) with the LS Entities pursuant to which Dynegy agreed to prepare and file with the SEC a “shelf” registration statement covering the resale of shares of Class A common stock issuable upon the conversion of (i) shares of Class B common stock that were issued to the LS Entities in the Merger and (ii) any shares of Class B common stock that may be transferred by the LS Entities to their respective limited partner investors. Dynegy filed this “shelf” registration statement with the SEC on April 5, 2007.

Under the LS Registration Rights Agreement, the LS Entities and their permitted transferees have the right to cause Dynegy to effect up to two underwritten offerings during the first 24 months following the Merger, provided that no more than one underwritten offering may be consummated during each of the first and second 12-month periods. The LS Entities and their permitted transferees may demand to effect up to two underwritten offerings during each 12-month period following the first 24 months after the Merger. We may defer the commencement of any underwritten offering demanded by the LS Entities and their permitted transferees for up to 60 days one time in any calendar year.

Stockholder Return Performance Presentation. The performance graph shown on the following page was prepared by Research Data Group, Inc., using data from the Research Data Group’s database. As required by applicable rules of the SEC, the graph was prepared based upon the following assumptions:

$100 was invested in Dynegy Class A common stock, the S&P 500, the 2007 Peer Group (as defined below) and the 2006 Peer Group (as defined below) on December 31, 2002.

The returns of each component company in the 2007 Peer Group and the 2006 Peer Group are weighed based on the market capitalization of such company at the beginning of the measurement period.

Dividends are reinvested on the ex-dividend dates.

Our peer group for the fiscal year ended December 31, 2007, which we refer to as the “2007 Peer Group”, is comprised of Mirant Corporation; NRG Energy, Inc.; and Reliant Energy, Inc. Our peer group for the fiscal year ended December 31, 2006, which we refer to as the “2006 Peer Group”, is comprised of AES Corporation; Mirant Corporation; NRG Energy, Inc.; and Reliant Energy, Inc.

For our 2007 Peer Group, we eliminated AES Corporation. We effected this change in an attempt to better reflect our current industry peers based on the comparability of each company’s size, asset profile and business focus and strategy. Namely, AES’s businesses include integrated utilities, distribution companies and generation facilities whereas our 2007 Peer Group consists of Independent Power Producers that are more similar to us.

LOGO

*	$100 invested on 12/31/02 in stock or index-including reinvestment of dividends. Fiscal year ending December 31.


	12/02	12/03	12/04	12/05	12/06	12/07
Dynegy Inc.	100.00	362.71	391.53	410.17	613.56	605.08
S&P 500	100.00	128.68	142.69	149.70	173.34	182.87
2007 Peer Group	100.00	230.00	402.46	408.36	555.98	825.79
2006 Peer Group	100.00	270.62	426.74	465.78	640.32	809.91

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

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

Unregistered Sales of Equity Securities and Use of Proceeds. Upon vesting of restricted stock awarded by Dynegy to employees, shares are withheld to cover the employees’ withholding taxes. Information on Dynegy’s purchases of equity securities during the quarter follows:


Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
October	—	—	—	N/A
November	—	—	—	N/A
December	879	7.57	—	N/A

Total	879	7.57	—	N/A

These were the only repurchases of equity securities made by Dynegy during the three months ended December 31, 2007. Dynegy does not have a stock repurchase program.

DHI

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

Item 6. Selected Financial Data

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

Dynegy’s Selected Financial Data


	Year Ended December 31,
	2007			2006			2005			2004			2003
	(in millions, except per share data)
Statement of Operations Data (1):
Revenues	$	3,103		$	1,770		$	2,017		$	2,249		$	2,376
Depreciation and amortization expense		(325	)		(217	)		(208	)		(221	)		(359	)
Goodwill impairment		—			—			—			—			(311	)
Impairment and other charges		—			(119	)		(46	)		(78	)		(225	)
General and administrative expenses		(203	)		(196	)		(468	)		(330	)		(315	)
Operating income (loss)		605			105			(832	)		(66	)		(769	)
Interest expense and debt conversion expense		(384	)		(631	)		(389	)		(453	)		(503	)
Income tax (expense) benefit		(151	)		152			393			158			292


	Year Ended December 31,
	2007			2006			2005			2004			2003
	(in millions, except per share data)
Income (loss) from continuing operations		116			(321	)		(800	)		(160	)		(813	)
Income (loss) from discontinued operations (3)		148			(13	)		895			145			81
Cumulative effect of change in accounting principles		—			1			(5	)		—			40
Net income (loss)	$	264		$	(333	)	$	90		$	(15	)	$	(692	)
Net income (loss) applicable to common stockholders (4)		264			(342	)		68			(37	)		321
Basic earnings (loss) per share from continuing operations	$	0.15		$	(0.72	)	$	(2.12	)	$	(0.48	)	$	0.53
Basic net income (loss) per share		0.35			(0.75	)		0.18			(0.10	)		0.86
Diluted earnings (loss) per share from continuing operations	$	0.15		$	(0.72	)	$	(2.12	)	$	(0.48	)	$	0.50
Diluted net income (loss) per share		0.35			(0.75	)		0.18			(0.10	)		0.78
Shares outstanding for basic EPS calculation		750			459			387			378			374
Shares outstanding for diluted EPS calculation		752			509			513			504			423
Cash dividends per common share	$	—		$	—		$	—		$	—		$	—
Cash Flow Data:
Net cash provided by (used in) operating activities	$	341		$	(194	)	$	(30	)	$	5		$	876
Net cash provided by (used in) investing activities		(817	)		358			1,824			262			(266	)
Net cash provided by (used in) financing activities		433			(1,342	)		(873	)		(115	)		(900	)
Cash dividends or distributions to partners, net		—			(17	)		(22	)		(22	)		—
Capital expenditures, acquisitions and investments		(504	)		(163	)		(315	)		(314	)		(338	)


	December 31,
	2007		2006		2005		2004		2003
	(in millions)
Balance Sheet Data (2):
Current assets	$	1,663	$	1,989	$	3,706	$	2,728	$	3,074
Current liabilities		999		1,166		2,116		1,802		2,450
Property and equipment, net		9,017		4,951		5,323		6,130		8,178
Total assets		13,221		7,537		10,126		9,843		12,801
Long-term debt (excluding current portion)		5,939		3,190		4,228		4,332		5,893
Notes payable and current portion of long-term debt		51		68		71		34		331
Serial preferred securities of a subsidiary		—		—		—		—		11
Series C convertible preferred stock		—		—		400		400		400
Minority interest		23		—		—		106		121
Capital leases not already included in long-term debt		5		6		—		—		—
Total equity		4,506		2,267		2,140		1,956		1,975

(1)

The Merger (April 2, 2007) and the Sithe Energies acquisition (February 1, 2005) were each accounted for in accordance with the purchase method of accounting and the results of operations attributable to the acquired businesses are included in our financial statements and operating statistics beginning on the acquisitions’ effective date for accounting purposes.

(2)

The Merger and the Sithe Energies acquisition 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 include the results of operations from the following businesses:

•

DGC (portions sold first and second quarters 2003);

•

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

•

DMSLP (sold fourth quarter 2005);

•

Calcasieu power generating facility (entered into an agreement to sell first quarter 2007); and

•

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

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

Dynegy Holdings’ Selected Financial Data


	Year Ended December 31,
	2007			2006			2005			2004			2003
	(in millions, except per share data)
Statement of Operations Data (1):
Revenues	$	3,103		$	1,770		$	2,017		$	1,447		$	1,303
Depreciation and amortization expense		(325	)		(217	)		(208	)		(210	)		(235	)
Goodwill impairment		—			—			—			—			—
Impairment and other charges		—			(119	)		(40	)		(24	)		(4	)
General and administrative expenses		(184	)		(193	)		(375	)		(285	)		(262	)
Operating income (loss)		624			108			(733	)		(202	)		(412	)
Interest expense and debt conversion expense		(384	)		(579	)		(383	)		(332	)		(332	)
Income tax (expense) benefit		(116	)		125			374			166			230
Income (loss) from continuing operations		176			(296	)		(727	)		(247	)		(353	)
Income (loss) from discontinued operations (2)		148			(12	)		813			143			77
Cumulative effect of change in accounting principles		—			—			(5	)		—			42
Net income (loss)	$	324		$	(308	)	$	81		$	(104	)	$	(234	)
Cash Flow Data:
Net cash provided by (used in) operating activities	$	368		$	(205	)	$	(24	)	$	(160	)	$	760
Net cash provided by (used in) investing activities		(688	)		357			1,839			(211	)		(423	)
Net cash provided by (used in) financing activities		369			(1,235	)		(734	)		289			(652	)
Capital expenditures, acquisitions and investments		(350	)		(155	)		(169	)		(219	)		(209	)


	December 31,
	2007		2006		2005		2004		2003
	(in millions)
Balance Sheet Data (1):
Current assets	$	1,614	$	1,828	$	3,457	$	2,192	$	2,460
Current liabilities		999		1,165		2,212		1,773		1,982
Property and equipment, net		9,017		4,951		5,323		6,130		6,302
Total assets		13,107		8,136		10,580		10,129		10,264
Long-term debt (excluding current portion)		5,939		3,190		4,003		4,107		3,664
Notes payable and current portion of long-term debt		51		68		191		34		150
Minority interest		23		—		—		106		121
Capital leases not already included in long-term debt		5		6		—		—		—
Total equity		4,597		3,036		3,331		3,085		3,241

(1)

The Contributed Entities assets were contributed to DHI contemporaneously with the Merger. This contribution was accounted for as a transaction between entities under common control. As such, the assets and liabilities were recorded by DHI at Dynegy’s historical cost on Dynegy’s date of acquisition. Additionally, the Sithe Energies assets were contributed to DHI on April 2, 2007. This contribution was accounted for as a transaction between entities under common control. As such, the assets and liabilities were recorded by DHI at Dynegy’s historical cost on Dynegy’s date of acquisition, January 31, 2005. In addition, DHI’s historical financial statements have been adjusted in all periods presented to reflect the contribution as though DHI had owned these assets beginning January 31, 2005. Please read Note 3—Business Combinations and Acquisitions—LS Assets Contribution and Note 3—Business Combinations and Acquisitions—Sithe Assets Contribution for further discussion.

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

•

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

•

DMSLP (sold fourth quarter 2005);

•

Calcasieu power generating facility (entered into an agreement to sell first quarter 2007); and

•

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

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

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

OVERVIEW

We are holding companies and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry. We report the results of our power generation business as three separate segments in our consolidated financial statements: (i) the Midwest segment (“GEN-MW”); (ii) the West segment (“GEN-WE”); and (iii) the Northeast segment (“GEN-NE”). We also separately report the results of our CRM business, which primarily consists of our legacy physical natural gas supply contracts, natural gas transportation contracts and power trading positions that remain from the third-party trading business that was substantially exited in 2002. 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. In connection with the Merger discussed in Note 3—Business Combinations and Acquisitions—LS Power Business Combination, our previously named South segment (“GEN-SO”) has been renamed GEN-WE and the power generation facilities located in California and Arizona acquired through the Merger are included in this segment. The Kendall and Ontelaunee power generation facilities acquired through the Merger are included in GEN-MW, and the Casco Bay and Bridgeport power generation facilities acquired through the Merger are included in GEN-NE. Our NGL business, which was comprised of our natural gas gathering and processing assets and integrated downstream assets used to fractionate, store, terminal, transport, distribute and market natural gas liquids was sold to Targa on October 31, 2005.

In addition to our operating generation facilities, we own an approximate 37 percent interest in PPEA which in turn owns a 57 percent undivided interest in Plum Point, a new 665 MW coal-fired power generation facility under construction in Arkansas, which is included in GEN-MW. We also own a 50 percent interest in SCEA, which owns a 75 percent undivided interest in Sandy Creek, an 898 MW power generation facility under construction in McLennan County, Texas, which is included in GEN-WE. Finally, through its interest in DLS Power Holdings, Dynegy owns a 50 percent interest in a portfolio of greenfield development and repowering and/or expansion opportunities with a diversity of fuel and dispatch types and geographic locations, which is described under “—Business Discussion—Power Generation Business—Development Joint Venture”.

The following is a brief discussion of each of our power generation segments, including a list of key factors that have affected, and are expected to continue to affect, their respective earnings and cash flows. We also present a brief discussion of our CRM business, Dynegy’s interest in the development joint venture and our corporate-level expenses. This “Overview” section concludes with a discussion of our 2007 company highlights. Please note that this “Overview” section is merely a summary and should be read together with the remainder of this Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, as well as our audited consolidated financial statements, including the notes thereto, and the other information included in this report.

Business Discussion

Power Generation Business

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

•

Prices for power, natural gas, coal and fuel oil which in turn are largely driven by supply and demand. Demand for power can vary due to weather and general economic conditions, among other things. For

example, a warm summer or a cold winter increases demand for electricity. Power supplies similarly vary by region and are impacted significantly by available generating capacity, transmission capacity and federal and state regulation; and

•

The relationship between prices for power and natural gas and prices for power and fuel oil, commonly referred to as the “spark spread”, which impacts the margin we earn on the electricity we generate. We believe that our significant coal-fired generating facilities provide a relative degree of earnings stability because our delivered cost of coal, particularly in the Midwest region, is relatively stable and positions us for potential increases in earnings and cash flows in an environment where power prices increase.

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

•

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

•

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

•

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

•

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

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

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

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

•

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

•

Our requirement to utilize a significant amount of cash for capital expenditures required to comply with the Midwest consent decree for the next several years;

•

Processes and regulations established by the Illinois Power Agency, which is expected to oversee the utility power procurement process in Illinois, which could impact our market opportunities; and

•

Changes in the existing PJM RPM capacity markets or in the bilateral MISO capacity markets may affect future capacity revenues.

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

•

Our ability to maintain the necessary permits to continue to operate our Moss Landing power generation facility with a once-through, seawater cooling system.

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

•

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

•

State-driven programs aimed at capping mercury and CO₂emissions would impose additional costs on our power generation facilities; and

•

The outcome of the appeals associated with the water permits at our Roseton and Danskammer facilities.

Customer Risk Management

Our CRM segment primarily consists of our legacy physical natural gas supply contracts, natural gas transportation contracts and power trading positions. We have substantially reduced the size of our CRM portfolio since October 2002, when we initiated our efforts to exit this business. Our legacy CRM business consists of a minimal number of power and natural gas trading positions that will remain until 2010 and 2017, respectively.

Development Joint Venture

Through its interest in DLS Power Development, Dynegy owns a 50 percent interest in a portfolio of greenfield development projects and repowering and/or expansion opportunities with a diversity of fuel and dispatch types and geographic locations. Dynegy’s development partner, LS Power, is actively pursuing a number of development options. The ability to successfully develop these projects will depend on:

•

The ability to obtain the necessary permits for the construction of new generating facilities;

•

The ability to obtain financing for the construction of new generating facilities; and

•

Demand for energy in the areas where we are evaluating development options, and our ability to market energy and capacity from these development projects.

Other

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

•

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

•

general and administrative costs, which will be impacted by, among other things, (i) any future corporate-level litigation reserves or settlements; (ii) staffing levels and associated expenses, particularly in the case of a successful merger or acquisition, and related integration activities; and (iii) 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.

2007 Highlights

LS Power. On April 2, 2007, upon the closing of the Merger, we acquired the Contributed Entities. The LS Contributing Entities received 340 million shares of Dynegy’s Class B common stock, $100 million in cash and a promissory note in the aggregate principal amount of $275 million (which was simultaneously issued and repaid in full without interest or prepayment penalty) in exchange for their contribution of their entire operating generation portfolio and a 50 percent interest in each of DLS Power Holdings and DLS Power Development

(together comprising the development joint venture with LS Associates). Dynegy also assumed certain debts and obligations. Please read Note 3—Business Combinations and Acquisitions—LS Power Business Combination for further information.

Upon the closing of the Merger, LS Associates transferred its interests in certain power generation development projects to DLS Power Holdings, and contributed 50 percent of the membership interests in DLS Power Holdings to Dynegy. In addition, immediately after the completion of the Merger, LS Associates and Dynegy each contributed $5 million to DLS Power Holdings as their initial capital contributions, and also contributed their respective interests in certain additional power generation development projects to DLS Power Holdings. LS Associates and Dynegy also each now own 50 percent of the membership interests in DLS Power Development.

Fifth Amended and Restated Credit Facility. Also on April 2, 2007, we entered into the Fifth Amended and Restated Credit Facility, which amended DHI’s credit facility by increasing the amount of the existing $470 million revolving credit facility (the “Revolving Facility”) to $850 million, increasing the amount of the existing $200 million term letter of credit facility (the “Term L/C Facility”) to $400 million and adding a $70 million senior secured term loan facility (“Term Loan B”). On May 24, 2007, we entered into an Amendment No. 1, dated as of May 24, 2007 (the “Credit Agreement Amendment”), to the Fifth Amended and Restated Credit Facility. The Credit Agreement Amendment increased the amount of the existing $850 million Revolving Facility to $1.15 billion and increased the amount of the existing $400 million Term L/C Facility to $850 million; the Credit Agreement Amendment did not affect the existing $70 million senior secured Term Loan B. The Credit Agreement Amendment also amended a pro forma leverage ratio requirement to allow DHI to issue the Notes (as defined below). Please read Note 15—Debt—Fifth Amended and Restated Credit Facility for further discussion.

Contributions from Dynegy to DHI. In April 2007, Dynegy contributed the Sithe Assets to DHI. This contribution was accounted for as a transaction between entities under common control. As such, the assets and liabilities of the Sithe Assets were recorded by DHI at Dynegy’s historical cost on the acquisition date. Also in April 2007, in connection with the completion of the Merger Agreement, Dynegy contributed to DHI its interest in the Contributed Entities and, as a result, the Contributed Entities are subsidiaries of DHI.

Senior Unsecured Bond Offering. In May 2007, we issued $1.1 billion aggregate principal amount of our 2019 Notes and $550 million aggregate principal amount of our 2015 Notes pursuant to the terms of a purchase agreement, by and among DHI and various purchasers. We used the net proceeds from the sale of the Notes to repay a portion of the debt assumed in the Merger. Please read Note 3—Business Combinations and Acquisitions—LS Power Business Combination and Note 15—Debt—Senior Notes offering for further discussion.

Sandy Creek. In connection with its acquisition of a 50 percent interest in DLS Power Holdings, as further discussed above, Dynegy acquired a 50 percent interest in SCEA. SCEA owns the Sandy Creek Energy Station (the “Sandy Creek Project”), which is a proposed 898 MW facility to be located in McLennan County, Texas. In August 2007, Sandy Creek Holdings, LLC (“SCH”) became a stand-alone entity separate from DLS Power Holdings and was contributed to DHI. SCH and its wholly owned subsidiaries, including SCEA, entered into various financing agreements to construct the Sandy Creek Project and sold a 25 percent undivided interest in the Sandy Creek Project to an unrelated third party. Please read Note 12—Variable Interest Entities—Sandy Creek for further information.

Illinois Rate Relief. In July 2007, we agreed to make payments of up to $25 million over a 29-month period in connection with legislation providing rate relief for electric consumers in the state of Illinois. We made a payment of $7.5 million in the third quarter 2007, and anticipate making payments of $9.0 million in 2008 and $8.5 million in 2009.

CoGen Lyondell Sale. In August 2007, we completed our sale of our CoGen Lyondell power generation facility for approximately $470 million to EnergyCo, LLC, a joint venture between PNM Resources and a subsidiary of Cascade Investment, LLC. We recorded a $224 million gain related to the sale of the asset in 2007. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—GEN-WE Discontinued Operations—CoGen Lyondell for further discussion.

Sale of Interest in Plum Point. In December 2007, we completed the sale of a portion of our indirect interest in the Plum Point Project for $82 million, net of non-recourse project debt. The non-controlling interest sold equates to approximately 125 MW in the Plum Point facility. The purchaser has assumed 50 percent of our contingent equity support obligations to the project lenders. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—PPEA Holding Company LLC for further discussion.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, collateral requirements, fixed capacity payments and contractual obligations, capital expenditures and working capital needs. Examples of working capital needs include prepayments or cash collateral associated with purchases of commodities, particularly natural gas and coal, facility maintenance costs (including required environmental expenditures) and other costs such as payroll. Our liquidity and capital resources are primarily derived from cash flows from operations, cash on hand, borrowings under our financing agreements, proceeds from asset sales and proceeds from capital market transactions to the extent we engage in these transactions. Additionally, DHI may borrow money from time to time from Dynegy.

Debt Obligations

During 2007, we continued our efforts to enhance our capital structure flexibility, reduce our outstanding debt and extend our maturity profile. On April 2, 2007, we assumed approximately $1.9 billion of debt upon completion of the Merger. Please read Note 3—Business Combinations and Acquisitions—LS Power Business Combination for further discussion.

Also on April 2, 2007, in connection with the Merger, an aggregate $275 million under the Revolving Facility, an aggregate $400 million under the Term L/C Facility (with the proceeds placed in a collateral account to support the issuance of letters of credit) and an aggregate $70 million under Term Loan B (representing all available borrowings under Term Loan B) were drawn under the Fifth Amended and Restated Credit Agreement.

In May 2007, we entered into the Credit Agreement Amendment. The Credit Agreement Amendment amended the Fifth Amended and Restated Credit Facility by increasing the amount of the existing $850 million Revolving Facility to $1.15 billion and increasing the amount of the existing $400 million Term L/C Facility to $850 million; the Credit Agreement Amendment did not affect the Term Loan B. The Credit Agreement Amendment also amended a pro forma leverage ratio requirement to allow DHI to issue the Notes.

In May 2007, DHI issued $1.1 billion aggregate principal amount of its 2019 Notes and $550 million aggregate principal amount of its 2015 Notes. DHI used the net proceeds from the sale of the Notes to repay a portion of the debt assumed in the Merger.

In August 2007, we repaid the $275 million borrowed under the Revolving Facility.

In September 2007, we completed the redemption of $11 million of DHI’s remaining outstanding 9.875 percent Second Priority Secured Notes due 2010 at a redemption price of 104.938 percent of the principal amount plus accrued and unpaid interest to the redemption date.

Please read Note 15—Debt for further discussion of these items. Following these transactions, our debt maturity profile as of December 31, 2007 includes $51 million in 2008, $58 million in 2009, $63 million in 2010, $570 million in 2011, $580 million in 2012 and approximately $4,668 million thereafter. Maturities for 2008 represent principal payments on the Sithe Senior Notes.

Summarized Debt and Other Obligations. The following table depicts our consolidated third party debt obligations, including the present value of the DNE leveraged lease payments discounted at 10 percent, and the extent to which they are secured as of December 31, 2007 and 2006:


	December 31, 2007			December 31, 2006
	(in millions)
First secured obligations	$	920		$	200
Second secured obligations		—			11
Unsecured obligations		5,015			3,375

Total corporate obligations		5,935			3,586
Secured non-recourse obligations (1)		806			448

Total obligations		6,741			4,034
Less: DNE lease financing (2)		(770	)		(801	)
Other (3)		19			25

Total notes payable and long-term debt (4)	$	5,990		$	3,258

(1)

Includes PPEA’s non-recourse project financing for its share of the construction of the Plum Point facility. Although we own a 37 percent economic interest in PPEA, we consolidate PPEA and its debt, as we are the primary beneficiary of this VIE. Also includes project financing associated with our Independence facility.

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

(3)	Consists of net premiums on debt of $19 million and $25 million at December 31, 2007 and 2006, respectively.

(4)	Does not include letters of credit.

Collateral Postings

We 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. The following table summarizes our consolidated collateral postings to third parties by line of business at February 21, 2008, December 31, 2007 and December 31, 2006:


	February 21, 2008		December 31, 2007		December 31, 2006
	(in millions)
By Business:
Generation business	$	1,253	$	1,130	$	134
Customer risk management business		13		14		54
Other		191		188		7

Total	$	1,457	$	1,332	$	195

By Type:
Cash (1)	$	91	$	53	$	38
Letters of credit		1,366		1,279		157

Total	$	1,457	$	1,332	$	195

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

The increase in collateral postings from December 31, 2007 to February 21, 2008 is primarily due to price and volume changes associated with collateral postings supporting our normal power and fuel purchases and sales.

The majority of the increase in collateral postings from December 31, 2006 to December 31, 2007 relates to an increase of approximately $620 million due to the completion of the Merger and incorporation of the letters of credit postings required by the Contributed Entities. Collateral requirements associated with the acquired entities included the following: approximately $350 million relating to hedging activities; approximately $101 million required to support Plum Point’s tax exempt bonds; approximately $15 million supporting our equity commitment to PPEA; approximately $90 million for environmental related requirements; and approximately $50 million of collateral requirements under transport and transmission agreements. During 2007, we also issued two letters of credit totaling $323 million in conjunction with the Sandy Creek Project and an $83 million letter of credit to satisfy the Sithe debt service reserve fund requirements that was previously funded with restricted cash. The balance of the increase relates to price and volume changes associated with collateral postings supporting our normal power and fuel purchases and sales. The $101 million supporting Plum Point’s tax exempt bonds and $83 million satisfying the Sithe debt service reserve requirement are included in Other in our segment reporting.

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. We believe that we have sufficient capital resources to satisfy counterparties’ collateral demands, including those for which no collateral is currently posted, for the foreseeable future.

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, 2007. Cash obligations reflected are not discounted and do not include accretion or dividends.


	Expiration by Period
	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
	(in millions)
Long-term debt (including current portion)	$	5,990	$	51	$	121	$	1,150	$	4,668
Interest payments on debt		3,633		443		882		943		1,365
Operating leases		1,343		166		283		330		564
Capital leases		14		2		4		4		4
Capacity payments		396		52		93		93		158
Transmission obligations		199		6		12		12		169
Interconnection obligations		20		1		2		2		15
Conditional purchase obligations		1		1		—		—		—
Pension funding obligations		48		29		19		—		—
Other obligations		64		26		20		7		11

Total contractual obligations	$	11,708	$	777	$	1,436	$	2,541	$	6,954

Long-Term Debt (Including Current Portion). Total amounts of Long-term debt (including current portion) are included in the December 31, 2007 consolidated balance sheet. Please read Note 15—Debt for further discussion.

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

In addition, we are party to two charter party agreements relating to VLGCs previously utilized in our global liquids business. The aggregate minimum base commitments of the charter party agreements are approximately $14 million each year for the years 2008 through 2010, and approximately $36 million from 2011 through lease expiration. The charter party rates payable under the two charter party agreements vary in accordance with market-based rates for similar shipping services. The $14 million and $36 million amounts set forth above are based on the minimum obligations set forth in the two charter party agreements. The primary terms of the charter party agreements expire August 2013 and August 2014, respectively. On January 1, 2003, in connection with the sale of our global liquids business, we sub-chartered both VLGCs to a wholly owned subsidiary of Transammonia Inc. The terms of the sub-charters are identical to the terms of the original charter agreements. We continue to rely on the sub-charters with a subsidiary of Transammonia to satisfy the obligations of our two charter party agreements. To date, the subsidiary of Transammonia has complied with the terms of the sub-charter agreements.

Capital Leases. In January 2006, we entered into an obligation under a capital lease related to a coal loading facility, which is 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 $14 million over the remaining term of the lease.

Capacity Payments. Capacity payments include fixed obligations associated with transmission, transportation and storage arrangements totaling approximately $396 million.

Transmission Obligations. In connection with the Merger Agreement, we assumed an obligation with respect to transmission services for our Griffith facility. This agreement expires in 2039. Our obligation under this agreement is approximately $6 million per year through the term of the contract.

Interconnection Obligations. In connection with the Merger Agreement, we assumed an obligation with respect to interconnection services for our Ontelaunee facility. This agreement expires in 2026. Our obligation under this agreement is approximately $1 million per year for through the term of the contract.

Pension Funding Obligations. Amounts include estimated defined benefit pension funding obligations for 2008—$29 million, 2009—$9 million and 2010—$10 million. Although we expect to continue to incur funding obligations subsequent to 2010, we cannot confidently estimate the amount of such obligations at this time and, therefore, have not included them in the table above.

Other Obligations. Other obligations include the following items:

•

$17.5 million related to Illinois rate relief legislation. We will pay $9 million in 2008 and $8.5 million in 2009. Please read Note 19—Commitments and Contingencies—Illinois Auction Complaints for further discussion;

•

Payments associated with a capacity contract between Independence and Con Edison. The aggregate payments through the 2014 expiration are approximately $15 million as of December 31, 2007. Please read Note 3—Business Combinations and Acquisitions—Sithe Energies Business Combination for more information on this agreement;

•

$13 million of reserves recorded in connection with FIN No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN No. 48”). Please read Note 17—Income Taxes—Unrecognized Tax Benefits for further discussion;

•

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 $7 million as of December 31, 2007; and

•

Agreements for the supply of water to our generating facilities.

Contingent Financial Obligations

The following table provides a summary of our contingent financial obligations as of December 31, 2007 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)	$	1,279	$	927	$	190	$	122	$	40
Surety bonds (2)		7		7		—		—		—
Guarantees (3)		4		4		—		—		—

Total financial commitments	$	1,290	$	938	$	190	$	122	$	40

(1)	Amounts include outstanding letters of credit.

(2)	Surety bonds are generally on a rolling 12-month basis. The $7 million of surety bonds are supported by collateral.

(3)

As part of a power purchase agreement with Constellation, we have guaranteed Constellation the receipt of $3.5 million in reactive power revenues over the four-year period of the power purchase agreement, which ends November 2008. This obligation will be partly offset by $2 million of reactive power revenue we expect to receive pursuant to our reactive power tariff filed with FERC.

Off-Balance Sheet Arrangements

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

As of December 31, 2007, future lease payments are $144 million for 2008, $141 million for 2009, $95 million for 2010, $112 million for 2011, $179 million for 2012 and $142 million for 2013, with $391 million in

the aggregate due from 2014 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, 2007, the present value (discounted at 10 percent) of future lease payments was $770 million.

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


	2007		2006		2005
	(in millions)
Lease expense	$	50	$	50	$	50
Lease payments (cash flows)	$	107	$	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 compensate the lessor for termination of the lease, including redeeming the pass-through trust certificates related to the unit or facility for which the lease was terminated at par plus accrued and unpaid interest. As of December 31, 2007, the termination payment at par would be approximately $1 billion for all of the leased 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 leased facilities, it would be difficult for DHI to raise sufficient funds to make this termination payment. Alternatively, if one or more of the leases were to be terminated because we determine, for reasons other than as a result of a change in law, that it has become economically or technologically obsolete or that it is no longer useful to our business, DHI must redeem the related pass-through trust certificates at par plus a make-whole premium in an amount equal to the discounted present value of the principal and interest payments still owing on the certificates being redeemed less the unpaid principal amount of such certificates at the time of redemption. For this purpose, the discounted present value would be calculated using a discount rate equal to the yield-to-maturity on the most comparable U.S. Treasury security plus 50 basis points.

Capital Expenditures

We continue to tightly manage our operating costs and capital expenditures. We had approximately $379 million in capital expenditures during 2007. Our 2007 capital spending by reportable segment was as follows (in millions):


GEN-MW	$	300
GEN-WE		17
GEN-NE		47
Other		15

Total	$	379

Capital spending in our GEN-MW segment primarily consisted of environmental and maintenance capital projects, as well as approximately $161 million spent on development capital related to the Plum Point Project. Capital spending in our GEN-WE and GEN-NE segments primarily consisted of maintenance projects.

We expect capital expenditures for 2008 to approximate $675 million, which is comprised of $550 million, $45 million, $60 million, and $20 million in the GEN-MW, GEN-WE, GEN-NE, and other segments, respectively. The $550 million of spending planned for GEN-MW includes $220 million related to construction of the Plum Point facility and $185 million of environmental expenditures related to the Midwest consent decree. Other spending primarily includes maintenance capital projects, environmental projects and limited development projects. The capital budget is subject to revision as opportunities arise or circumstances change.

Our long term capital expenditures in the GEN-MW segment will be significantly impacted by the Midwest consent decree, which obligates us to, among other things, install additional emission controls at our Baldwin and Havana plants. We expect our costs associated with the Midwest consent decree projects to increase. Please read “—Environmental Matters—The Clean Air Act” for further discussion. In addition, we expect capital expenditures of approximately $440 million in the years 2008 through 2010 related to the Plum Point facility that is currently under construction. These capital expenditures will be funded by non-recourse project debt. Please read Note 15—Debt—Plum Point Credit Agreement Facility for further discussion.

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

Dividends on Dynegy Common Stock

Dividend payments on Dynegy’s common stock are at the discretion of its Board of Directors. Dynegy did not declare or pay a dividend on its common stock for the year ended December 31, 2007 and it does not foresee a declaration of dividends in the near term.

Internal Liquidity Sources

Our primary internal liquidity sources are cash flows from operations, cash on hand and available capacity under our Fifth Amended and Restated Credit Facility, which is scheduled to mature in April 2012. Additionally, from time to time, DHI may borrow money from its parent.

Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at February 21, 2008, December 31, 2007 and December 31, 2006:


	February 21, 2008			December 31, 2007			December 31, 2006
	(in millions)
Revolver capacity (1)	$	1,150		$	1,150		$	470
Term letter of credit capacity, net of required reserves		825			825			194
Plum Point and Sandy Creek letter of credit capacity		425			425			—
Outstanding letters of credit		(1,366	)		(1,279	)		(157	)

Unused capacity		1,034			1,121			507
Cash—DHI (2)		388			292			243

Total available liquidity—DHI		1,422			1,413			750
Cash—Dynegy		29			36			128

Total available liquidity—Dynegy	$	1,451		$	1,449		$	878

(1)

In April 2007, we amended and restated the credit facility, and in May 2007, we further amended it. Please read Note 15—Debt—Fifth Amended and Restated Credit Facility for further discussion. Our term letter of credit facility capacity is limited by, and will increase or decrease with changes in cash collateral on deposit.

(2)	The February 21, 2008, December 31, 2007 and December 31, 2006 amounts include approximately zero, zero, and $46 million, respectively, of cash that remains in European subsidiaries and $13 million, $5 million and $10 million, respectively, of cash that remains in Canadian subsidiaries.

Cash Flows from Operations. Dynegy had operating cash flows of $341 million for the year ended December 31, 2007. This consisted of $934 million in operating cash flows from our power generation business, reflecting positive earnings for the period and increases in working capital due to returns of cash collateral postings. These cash flows were offset by $593 million of cash outflows primarily relating to corporate-level expenses.

DHI had operating cash flows of $368 million for the year ended December 31, 2007. This consisted of $934 million in operating cash flows from our power generation business, reflecting positive earnings for the period and increases in working capital due to returns of cash collateral postings. These cash flows were offset by $566 million of cash outflows primarily relating to corporate-level expenses.

Please read “—Results of Operations—Year Ended 2007 Compared to Year Ended 2006—Operating Income” and “—Cash Flow Disclosures” for further discussion of factors impacting our operating cash flows for the periods presented.

Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of natural gas and its correlation to power prices, the cost of coal and fuel oil and the value of capacity and ancillary services. Additionally, the availability of our plants during peak demand periods will be required to allow us to capture attractive market prices when available. Over the longer term, our operating cash flows also will be impacted by, among other things, the regulatory environment, and our ability to manage tightly our operating costs, including maintenance costs. Our ability to achieve targeted cost savings in the face of industry-wide increases in labor and benefits costs, together with changes in commodity prices, will impact our future operating cash flows. Please read “—Results of Operations—2008 Outlook” for further discussion.

Cash on Hand. At February 21, 2008 and December 31, 2007, Dynegy had cash on hand of $417 million and $328 million, respectively, as compared to $371 million at the end of 2006. The change in cash on hand at February 21, 2008 and December 31, 2007 as compared to the end of 2006 is primarily attributable to cash provided by the operating activities of our generating business, proceeds received from the sale of our CoGen Lyondell facility and proceeds received from net long-term borrowings, largely offset by 2007 capital expenditures, cash restricted to support our credit facility and capital commitments in connection with the Sandy Creek Project, and cash paid in connection with the Merger.

At February 21, 2008 and December 31, 2007, DHI had cash on hand of $388 million and $292 million, respectively, as compared to $243 million at the end of 2006. The increase in cash on hand at February 21, 2008 and December 31, 2007 as compared to the end of 2006 is primarily attributable to cash provided by the operating activities of our generating business, proceeds received from the sale of our CoGen Lyondell facility and proceeds received from net long-term borrowings. These inflows were largely offset by 2007 capital expenditures, cash restricted to support our credit facility and capital commitments in connection with the Sandy Creek Project and dividends paid to Dynegy.

Revolver Capacity. On April 2, 2007, DHI entered into the Fifth Amended and Restated Credit Facility, which is our primary credit facility. On May 24, 2007, DHI entered into an amendment to the Fifth Amended and Restated Credit Facility. As of February 21, 2008, $1,366 million in letters of credit are outstanding but undrawn, and we have no revolving loan amounts drawn under the Fifth Amended and Restated Credit Facility. Please read Note 15—Debt—Fifth Amended and Restated Credit Facility for further discussion of our amended credit facility.

External Liquidity Sources

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

Asset Sale Proceeds. On December 13, 2007, we sold a non-controlling ownership interest in PPEA for approximately $82 million. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—PPEA Holding Company LLC for further discussion.

On August 1, 2007, we sold our CoGen Lyondell power generation facility for approximately $470 million. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—GEN-WE Discontinued Operations—CoGen Lyondell for further discussion.

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

Consistent with industry practice, we regularly evaluate our generation fleet based primarily on geographic location, fuel supply, market structure and market recovery expectations. We consider divestitures of non-core generation assets where the balance of the above factors suggests that such assets’ earnings potential is limited or that the value that can be captured through a divestiture outweighs the benefits of continuing to own and operate such assets. Moreover, dispositions of one or more generation facilities could occur in 2008 or beyond. Were any such sale or disposition to be consummated, the disposition could result in accounting charges related to the affected assets, and our future earnings and cash flows could be affected.

Capital-Raising Transactions. As part of our ongoing efforts to maintain a capital structure that is closely aligned with the cash-generating potential of our asset-based business, which is subject to cyclical changes in commodity prices, we may explore additional sources of external liquidity. The timing of any transaction may be impacted by events, such as strategic growth opportunities, development activities, legal judgments or regulatory requirements, which could require us to pursue additional capital in the near-term. The receptiveness of the capital markets to an offering of debt or equity securities 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, including a lack of investment capital brought about by general economic conditions. Any issuance of equity by Dynegy likely would have other effects as well, including stockholder dilution. Our ability to issue debt securities is limited by our financing agreements, including our Fifth Amended and Restated Credit Facility, as amended. Please read Note 15—Debt for further discussion.

In addition, we continually review and discuss opportunities to grow our company and to participate in what we believe will be continuing consolidation of the power generation industry. No such definitive transaction has been agreed to and none can be guaranteed to occur; however, we have successfully executed on similar opportunities in the past and could do so again in the future. Depending on the terms and structure of any such transaction, we could issue significant debt and/or equity securities for capital-raising purposes. We also could be required to assume substantial debt obligations and the underlying payment obligations.

Capital Allocation. We continually review our investment options with respect to our capital resources. We do not have any material debt maturities until 2011, and between now and then we expect to significantly enhance our current capital resources through the results of our operating business. We will seek to invest these capital resources in various projects and activities based on their return to stockholders. Potential investments could include, among others: add-on or other enhancement projects associated with our current power generation assets; greenfield or brownfield development projects; merger and acquisition activities; and returns of capital to shareholders through, for example, a share buy-back. Capital allocation determinations generally are subject to the discretion of Dynegy’s Board of Directors, and may be limited by the provisions of our credit agreement. Any particular use of capital in an amount that is not considered material may be made without any prior public disclosure and could occur at any time.

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

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 2007, 2006 and 2005. At the end of this section, we have included our business outlook for each segment.

We report results of our power generation business in the following segments: (i) GEN-MW, (ii) GEN-WE and (iii) GEN-NE. Following the completion of the Merger, our previously named South segment has been renamed the GEN-WE segment and the power generation facilities located in California and Arizona acquired through the Merger are included in this segment. The Kendall, Ontelaunee and Plum Point power generation facilities acquired through the Merger are included in GEN-MW, and the Casco Bay and Bridgeport power generation facilities acquired through the Merger are included in GEN-NE. We also separately report results of our CRM business, which primarily consists of legacy physical gas supply contracts, gas transportation contracts and power trading positions that remain from the third-party trading business that was substantially exited in 2002. Our consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization. Because of the diversity among their respective operations, we report the results of each business as a separate segment in our consolidated financial statements. Dynegy’s 50 percent investment in DLS Power Development is included in Other for segment reporting.

As described below, substantially all of our NGL business, which was conducted through DMSLP and its subsidiaries and comprised our NGL reportable segment, was sold to Targa on October 31, 2005.

Summary Financial Information. The following tables provide summary financial data regarding Dynegy’s consolidated and segmented results of operations for 2007, 2006 and 2005, respectively.

Dynegy’s Results of Operations for the Year Ended December 31, 2007


	Power Generation
	GEN-MW			GEN-WE			GEN-NE			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	1,325		$	689		$	1,076		$	13		$	—		$	3,103
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(675	)		(486	)		(867	)		17			(2	)		(2,013	)
Depreciation and amortization expense		(194	)		(73	)		(45	)		—			(13	)		(325	)
Gain on sale of assets, net		39			—			—			4			—			43
General and administrative expense		—			—			—			(15	)		(188	)		(203	)

Operating income (loss)	$	495		$	130		$	164		$	19		$	(203	)	$	605
Earnings (losses) from unconsolidated investments		—			6			—			—			(9	)		(3	)
Other items, net		(7	)		—			—			(5	)		61			49
Interest expense																	(384	)

Income from continuing operations before taxes																	267
Income tax expense																	(151	)

Income from continuing operations																	116
Income from discontinued operations, net of taxes																	148

Net income																$	264

Dynegy’s Results of Operations for the Year Ended December 31, 2006


	Power Generation
	GEN-MW			GEN-WE			GEN-NE			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	969		$	87		$	609		$	105		$	—		$	1,770
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(483	)		(72	)		(530	)		(45	)		(6	)		(1,136	)
Depreciation and amortization expense		(168	)		(8	)		(24	)		—			(17	)		(217	)
Impairment and other charges		(110	)		(9	)		—			—			—			(119	)
Gain on sale of assets, net		—			—			—			—			3			3
General and administrative expense		—			—			—			(53	)		(143	)		(196	)

Operating income (loss)	$	208		$	(2	)	$	55		$	7		$	(163	)	$	105
Losses from unconsolidated investments		—			(1	)		—			—			—			(1	)
Other items, net		2			1			9			4			38			54
Interest expense and debt conversion costs																	(631	)

Loss from continuing operations before taxes																	(473	)
Income tax benefit																	152

Loss from continuing operations																	(321	)
Loss from discontinued operations, net of taxes																	(13	)
Cumulative effect of change in accounting principle, net of taxes																	1

Net loss																$	(333	)

Dynegy’s Results of Operations for the Year Ended December 31, 2005


	Power Generation
	GEN-MW			GEN-WE			GEN-NE			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	947		$	109		$	902		$	59		$	—		$	2,017
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(525	)		(102	)		(830	)		(667	)		(2	)		(2,126	)
Depreciation and amortization expense		(157	)		(11	)		(21	)		(1	)		(18	)		(208	)
Impairment and other charges		(36	)		—			—			—			(10	)		(46	)
Gain (loss) on sale of assets, net		(2	)		—			—			—			1			(1	)
General and administrative expense		(33	)		(11	)		(22	)		(38	)		(364	)		(468	)

Operating income (loss)	$	194		$	(15	)	$	29		$	(647	)	$	(393	)	$	(832	)
Earnings (losses) from unconsolidated investments		7			(5	)		—			—			—			2
Other items, net		2			(1	)		5			—			20			26
Interest expense																	(389	)

Loss from continuing operations before taxes																	(1,193	)
Income tax benefit																	393

Loss from continuing operations																	(800	)
Income from discontinued operations, net of taxes																	895
Cumulative effect of change in accounting principle, net of taxes																	(5	)

Net income																$	90

The following tables provide summary financial data regarding DHI’s consolidated and segmented results of operations for 2007, 2006 and 2005, respectively.

DHI’s Results of Operations for the Year Ended December 31, 2007


	Power Generation
	GEN-MW			GEN-WE			GEN-NE			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	1,325		$	689		$	1,076		$	13		$	—		$	3,103
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(675	)		(486	)		(867	)		17			(2	)		(2,013	)
Depreciation and amortization expense		(194	)		(73	)		(45	)		—			(13	)		(325	)
Gain on sale of assets, net		39			—			—			4			—			43
General and administrative expense		—			—			—			(15	)		(169	)		(184	)

Operating income (loss)	$	495		$	130		$	164		$	19		$	(184	)	$	624
Earnings from unconsolidated investments		—			6			—			—			—			6
Other items, net		(7	)		—			—			(5	)		58			46
Interest expense																	(384	)

Income from continuing operations before taxes																	292
Income tax expense																	(116	)

Income from continuing operations																	176
Income from discontinued operations, net of taxes																	148

Net income																$	324

DHI’s Results of Operations for the Year Ended December 31, 2006


	Power Generation
	GEN-MW			GEN-WE			GEN-NE			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	969		$	87		$	609		$	105		$	—		$	1,770
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(483	)		(72	)		(530	)		(45	)		(6	)		(1,136	)
Depreciation and amortization expense		(168	)		(8	)		(24	)		—			(17	)		(217	)
Impairment and other charges		(110	)		(9	)		—			—			—			(119	)
Gain on sale of assets, net		—			—			—			—			3			3
General and administrative expense		—			—			—			(53	)		(140	)		(193	)

Operating income (loss)	$	208		$	(2	)	$	55		$	7		$	(160	)	$	108
Losses from unconsolidated investments		—			(1	)		—			—			—			(1	)
Other items, net		2			1			9			4			35			51
Interest expense and debt conversion costs																	(579	)

Loss from continuing operations before taxes																	(421	)
Income tax benefit																	125

Loss from continuing operations																	(296	)
Loss from discontinued operations, net of taxes																	(12	)

Net loss																$	(308	)

DHI’s Results of Operations for the Year Ended December 31, 2005


	Power Generation
	GEN-MW			GEN-WE			GEN-NE			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	947		$	109		$	902		$	59		$	—		$	2,017
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(525	)		(102	)		(830	)		(667	)		(2	)		(2,126	)
Depreciation and amortization expense		(157	)		(11	)		(21	)		(1	)		(18	)		(208	)
Impairment and other charges		(30	)		—			—			—			(10	)		(40	)
Gain on sale of assets, net		(2	)		—			—			—			1			(1	)
General and administrative expense		(34	)		(12	)		(22	)		(38	)		(269	)		(375	)

Operating income (loss)	$	199		$	(16	)	$	29		$	(647	)	$	(298	)	$	(733	)
Earnings (losses) from unconsolidated investments		7			(7	)		—			—			—			—
Other items, net		2			(1	)		5			—			9			15
Interest expense																	(383	)

Loss from continuing operations before taxes																	(1,101	)
Income tax benefit																	374

Loss from continuing operations																	(727	)
Income from discontinued operations, net of taxes																	813
Cumulative effect of change in accounting principle, net of taxes																	(5	)

Net income																$	81

The following table provides summary segmented operating statistics for 2007, 2006 and 2005, respectively:


	Year Ended December 31,
	2007		2006		2005
GEN-MW
Million Megawatt Hours Generated		25.0		21.5		21.9
Average On-Peak Market Power Prices ($/MWh) (1):
Cinergy (Cin Hub)	$	61	$	52	$	64
Commonwealth Edison (NI Hub)	$	59	$	52	$	62
PJM West	$	71	$	62	$	77
Average Market Spreads ($/MWh) (4)
PJM West	$	17	$	10	$	9

GEN-WE
Million Megawatt Hours Generated (2)(3)		11.1		0.9		2.0
Average On-Peak Market Power Prices ($/MWh) (1):
North Path 15 (NP 15)	$	67	$	61	$	72
Palo Verde	$	62	$	58	$	67
Average Market Spreads ($/MWh) (4):
North Path 15 (NP 15)	$	16	$	14	$	17
Palo Verde	$	13	$	12	$	11


	Year Ended December 31,
	2007			2006			2005
GEN-NE
Million Megawatt Hours Generated		9.4			4.4			8.3
Average On-Peak Market Power Prices ($/MWh) (1):
New York—Zone G	$	84		$	76		$	92
New York—Zone A	$	64		$	59		$	76
Mass Hub	$	78		$	70		$	90
Average Market Spreads ($/MWh) (4):
New York—Zone A	$	12		$	9		$	13
Mass Hub	$	23		$	19		$	22
Fuel oil	$	(16	)	$	(10	)	$	14
Average natural gas price—Henry Hub ($/MMBtu) (5)	$	6.95		$	6.74		$	8.80

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

(2)

Includes our ownership percentage in the MWh generated by our GEN-WE investment in Black Mountain for the years ended December 31, 2007, 2006 and 2005 and our ownership percentage in the MWh generated by our GEN-WE investment in West Coast Power and Panama for the years ended December 31, 2006 and 2005.

(3)

Excludes approximately 1.7 million MWh, 2.9 million MWh and 3.2 million MWh generated by our CoGen Lyondell facility, which we sold in August 2007, and less than 0.1 million MWh, less than 0.1 million MWh and less than 0.1 million MWh generated by our Calcasieu facility, which is classified as held for sale, for the years ended December 31, 2007, 2006 and 2005, respectively.

(4)	Reflects the simple average of the spark spread available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price.

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

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, 2007
	Power Generation
	GEN-MW			GEN-WE		GEN-NE		CRM			Other & Eliminations			Total
	(in millions)
Discontinued operations (1)	$	—		$	225	$	—	$	15		$	(1	)	$	239
Legal and settlement charges					—		—		(15	)		(2	)		(17	)
Illinois rate relief charge		(25	)		—		—		—			—			(25	)
Change in fair value of interest rate swaps, net of minority interest		(9	)		—		—		—			39			30
Gain on sale of Sandy Creek ownership interest		—			10		—		—			—			10
Gain on sale of Plum Point ownership interest		39			—		—		—			—			39
Settlement of Kendall toll		—			—		—		31			—			31
Taxes		—			—		—		—			30			30

Total—DHI		5			235		—		31			66			337
Legal and settlement charges		—			—		—		—			(19	)		(19	)
Taxes		—			—		—		—			(20	)		(20	)

Total—Dynegy	$	5		$	235	$	—	$	31		$	27		$	298

(1)	Discontinued operations for GEN-WE includes a gain on the sale of the CoGen Lyondell power generation facility of $224 million.


	Year Ended December 31, 2006
	Power Generation
	GEN-MW			GEN-WE			GEN-NE			CRM			Other & Eliminations			Total
	(in millions)
Debt conversion costs	$	—		$	—		$	—		$	—		$	(204	)	$	(204	)
Asset impairments		(110	)		(9	)		—			—			—			(119	)
Legal and settlement charges		—			—			—			(53	)		—			(53	)
Sithe Subordinated Debt exchange charge		—			—			(36	)		—			—			(36	)
Acceleration of financing costs		—			—			—			—			(34	)		(34	)
Taxes		—			—			—			—			(29	)		(29	)
Discontinued operations		—			(53	)		—			23			6			(24	)

Total—DHI		(110	)		(62	)		(36	)		(30	)		(261	)		(499	)
Debt conversion costs		—			—			—			—			(45	)		(45	)
Acceleration of financing costs		—			—			—			—			(2	)		(2	)
Discontinued operations		—			—			—			—			1			1

Total—Dynegy	$	(110	)	$	(62	)	$	(36	)	$	(30	)	$	(307	)	$	(545	)


	Year Ended December 31, 2005
	Power Generation
	GEN-MW			GEN-WE			GEN-NE		CRM			Other & Eliminations			Total
	(in millions)
Discontinued operations (1)	$	—		$	(6	)	$	—	$	6		$	1,250		$	1,250
Sterlington toll settlement		—			—			—		(364	)		—			(364	)
Legal and settlement charges		—			—			—		(38	)		(154	)		(192	)
Independence toll settlement		—			—			—		(169	)		—			(169	)
Asset impairment		(29	)		—			—		—			—			(29	)
Impairment of generation assets		—			(23	)		—		—			—			(23	)
Restructuring costs		—			—			—		—			(11	)		(11	)
Taxes		—			—			—		—			24			24

Total—DHI		(29	)		(29	)		—		(565	)		1,109			486
Legal and settlement charges		—			—			—		—			(95	)		(95	)
Impairment of generation assets		—			(4	)		—		—			—			(4	)
Taxes		—			—			—		—			65			65

Total—Dynegy	$	(29	)	$	(33	)	$	—	$	(565	)	$	1,079		$	452

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

Year Ended 2007 Compared to Year Ended 2006

Operating Income

Operating income for Dynegy was $605 million for the year ended December 31, 2007, compared to $105 million for the year ended December 31, 2006. Operating income for DHI was $624 million for the year ended December 31, 2007, compared to $108 million for the year ended December 31, 2006.

Power Generation—Midwest Segment. Operating income for GEN-MW was $495 million for the year ended December 31, 2007, compared to $208 million for the year ended December 31, 2006. Operating income for 2007 included a $39 million pre-tax gain related to the partial sale of our ownership interest in PPEA Holdings. Operating income for 2006 included a $110 million pre-tax impairment charge related to the Bluegrass generation facility, due to changes in the market that resulted in economic constraints on the facility.

Revenues for the year ended December 31, 2007 increased by $356 million compared to the year ended December 31, 2006, and cost of sales increased by $192 million, resulting in a net increase of $164 million. The increase was primarily driven by the following:

•

Higher volumes—Generated volumes increased by 16 percent, up from 21.5 million MWh for the year ended December 31, 2006 to 25 million MWh for the year ended December 31, 2007;

•

Increased market prices—The average actual on-peak prices in Cin Hub pricing region increased from $52 per MWh for the year ended December 31, 2006 to $61 per MWh for the year ended December 31, 2007;

•

Improved pricing as a result of the Illinois reverse power procurement auction—Beginning January 1, 2007, we began operating under two new energy product supply agreements with subsidiaries of Ameren Corporation through our participation in the Illinois reverse power procurement auction in 2006. Under these new agreements, we provide up to 1,400 MWh around the clock for prices of approximately $64.77 per megawatt-hour; and

•

The addition of the new Midwest plants acquired through the Merger—The Kendall and Ontelaunee plants acquired on April 2, 2007 contributed to the increase in generated volumes and provided results of $62 million for the year ended December 31, 2007, exclusive of mark-to-market losses discussed below.

These items were offset by the following:

•

Mark-to-market losses—GEN-MW’s results for the year ended December 31, 2007 included mark-to-market losses of $36 million related to forward sales, compared to $15 million of mark-to-market gains for the year ended December 31, 2006. Of the $36 million in 2007 mark-to-market losses, $13 million related to previously recognized mark-to-market gains that settled in 2007, and the remaining $23 million related to positions that will settle in 2008 and beyond. See Note 6—Risk Management Activities and Financial Instruments—Accounting for Derivative Instruments and Hedging Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007; and

•

A $25 million charge related to the Illinois rate relief package—In July 2007, we entered into agreements with various parties to make payments of up to $25 million in connection with legislation providing for rate relief for Illinois electric consumers. During September 2007, we made an initial payment of $7.5 million. During 2007, we recorded a pre-tax charge of $25 million, included as a cost of sales on our consolidated statements of operations. Please read Note 19—Commitments and Contingencies—Legal Proceedings—Illinois Auction Complaints for further discussion.

Depreciation expense increased from $168 million for the year ended December 31, 2006 to $194 million for the year ended December 31, 2007, primarily as a result of the new Midwest plants and capital projects placed into service in 2006.

Power Generation—West Segment. Operating income for GEN-WE was $130 million for the year ended December 31, 2007, compared to a loss of $2 million for the year ended December 31, 2006. The 2006 results relate to our Heard County and Rockingham generation facilities. Results from our CoGen Lyondell and Calcasieu power generation facilities have been classified as discontinued operations for all periods presented.

Revenues for the year ended December 31, 2007 increased by $602 million compared to the year ended December 31, 2006, and cost of sales increased by $414 million, resulting in a net increase of $188 million. The increase was primarily driven by the following:

•

The addition of the new West plants acquired through the Merger – Generated volumes were 11.1 million MWh for the year ended December 31, 2007, up from 0.9 million MWh for the year ended

December 31, 2006. The volume increase was primarily driven by the new West plants, which provided total results of $156 million for the year ended December 31, 2007, exclusive of mark-to-market gains discussed below. The volume increase from the new West plants was slightly offset by a reduction due to the sale of the Rockingham generation facility in late 2006; and

•

Mark-to-market gains – GEN-WE’s results for the year ended December 31, 2007 included mark-to-market gains of $44 million related to heat rate call-options and forward sales agreements, compared to zero for the year ended December 31, 2006. Of the $44 million in 2007 mark-to-market gains, $15 million related to risk management liabilities acquired in the Merger that settled in 2007, and the remaining $29 million related to positions that will settle in 2008 and beyond. See Note 6—Risk Management Activities and Financial Instruments—Accounting for Derivative Instruments and Hedging Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007.

Depreciation expense increased from $8 million for the year ended December 31, 2006 to $73 million for the year ended December 31, 2007 primarily as a result of the new West plants. In addition, during 2006, we recorded a $9 million impairment of our Rockingham facility, resulting from the announcement of our sale of the facility.

Power Generation—Northeast Segment. Operating income for GEN-NE was $164 million for the year ended December 31, 2007, compared to $55 million for the year ended December 31, 2006.

Revenues for the year ended December 31, 2007 increased by $467 million compared to the year ended December 31, 2006, and cost of sales increased by $337 million, resulting in a net increase of $130 million. The increase was primarily driven by the following:

•

Increased market prices and spark spreads—On peak market prices in New York Zone G and Zone A increased by 11 percent and 8 percent, respectively. Spark spreads widened due to higher power prices. Average market spark spreads increased 33 percent and 21 percent for New York Zone A and Mass Hub, respectively;

•

Higher volumes, partially driven by the addition of the new Northeast plants acquired through the Merger—Generated volumes increased by 114 percent, up from 4.4 million MWh for the year ended December 31, 2006 to 9.4 million MWh for the year ended December 31, 2007. The volume increase was partially driven by the new Northeast plants. The Bridgeport and Casco Bay plants provided total results of $90 million for the year ended December 31, 2007, exclusive of mark-to-market losses discussed below. The volume increase was also a result of higher spark spreads and cooler weather in the first quarter 2007, which led to greater run times than in 2006; and

•

A fuel oil inventory write-down of approximately $6 million was recorded in the year ended December 31, 2006.

These items were offset by the following:

•

Mark-to-market losses—GEN-NE’s results for the year ended December 31, 2007 included mark-to-market losses of $40 million related to forward sales, compared to losses of $26 million for the year ended December 31, 2006. Of the $40 million in 2007 mark-to-market losses, $32 million related to risk management assets acquired in the Merger that settled in 2007. The remaining $8 million related to positions that will settle in 2008 and beyond. See Note 6—Risk Management Activities and Financial Instruments—Accounting for Derivative Instruments and Hedging Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007; and

•

Results were favorably impacted in 2006 by $12 million due to an opportunistic sale of emissions credits that were not required for near-term operations of our facilities. Similar sales of $10 million occurred in 2007.

Depreciation expense increased from $24 million for the year ended December 31, 2006 to $45 million for the year ended December 31, 2007. This was primarily due to the new Northeast plants.

CRM. Operating income for the CRM segment was $19 million for the year ended December 31, 2007, compared to $7 million for the year ended December 31, 2006. Results for 2007 include a $31 million gain associated with the acquisition of Kendall pursuant to EITF Issue No. 04-1. Prior to the Merger, Kendall held a power tolling contract with our CRM segment. Upon completion of the Merger, this contract became an intercompany agreement, and was effectively eliminated on a consolidated basis, resulting in the $31 million gain that is included in cost of sales on our consolidated statements of operations. Please read Note 3—Business Combinations and Acquisitions—LS Power Business Combination for further discussion.

Results for 2007 and 2006 reflect legal and settlement charges of approximately $15 million and $53 million, respectively, resulting from additional activities during the period that negatively affected management’s assessment of probable and estimable losses associated with the applicable proceedings. The 2007 legal and settlement charges were partially offset by a $4 million gain on the sale of NYMEX securities. The 2006 legal and settlement charges were partially offset by mark-to-market income on our legacy coal, natural gas, emissions, and power positions.

Other. Dynegy’s other operating loss for the year ended December 31, 2007 was $203 million, compared to an operating loss of $163 million for the year ended December 31, 2006. Operating losses in both periods were comprised primarily of general and administrative expenses.

Dynegy’s consolidated general and administrative expenses increased to $203 million for the year ended December 31, 2007 from $196 million for the year ended December 31, 2006. General and administrative expenses for the year ended December 31, 2007 included legal and settlement charges of $36 million, compared with legal and settlement charges of $53 million in the same period of 2006. For the years ended December 31, 2007 and 2006, $15 million and $53 million, respectively, of this general and administrative expense was related to legal and settlement charges reported in our CRM segment, as discussed above. Additionally, general and administrative expenses for 2007 included a charge of approximately $6 million in connection with the accelerated vesting of restricted stock and stock option awards previously granted to employees, which vested in full upon closing of the Merger. The remaining increase from 2006 to 2007 was primarily a result of higher salary and employee benefit costs due to the Merger.

DHI’s other operating loss for the year ended December 31, 2007 was $184 million, compared to an operating loss of $160 million for the year ended December 31, 2006. Operating losses in both periods were comprised primarily of general and administrative expense.

DHI’s consolidated general and administrative expenses decreased to $184 million for the year ended December 31, 2007 from $193 million for the year ended December 31, 2006. General and administrative expenses for the year ended December 31, 2007 included legal and settlement charges of $17 million, compared with legal and settlement charges of $53 million in the same period of 2006. For the years ended December 31, 2007 and 2006, $15 million and $53 million, respectively, of this general and administrative expense was related to legal, respectively charges reported in our CRM segment, as discussed above. The decrease in legal and settlement charges from 2006 to 2007 was partially offset by a charge of approximately $6 million in 2007 related to the accelerated vesting of restricted stock and stock option awards previously granted to employees, which vested in full upon closing of the Merger. Additionally, salary and employee benefit costs were higher in 2007 as a result of the Merger.

Earnings from Unconsolidated Investments

Dynegy’s losses from unconsolidated investments were $3 million for the year ended December 31, 2007 compared to losses of $1 million for the year ended December 31, 2006. Earnings in 2007 included $10 million from the GEN-WE investment in the Sandy Creek largely due to its share of the gain on SCEA’s sale of a 25 percent undivided interest in the Sandy Creek Project. Please read Note 12—Variable Interest Entities—Sandy Creek for further information. This income was partially offset by losses related to Dynegy’s interest in DLS Power Holdings. Earnings in 2006 related to the GEN-WE investment in Black Mountain.

DHI’s earnings from unconsolidated investments were $6 million for the year ended December 31, 2007, compared with losses of $1 million the year ended December 31, 2006. Earnings in 2007 included $10 million from the GEN-WE investment in the Sandy Creek largely due to its share of the gain on SECA’s sale of a 25 percent undivided interest in the Sandy Creek Project. Please read Note 12—Variable Interest Entities—Sandy Creek for further information. Earnings in 2006 related to the GEN-WE investment in Black Mountain.

Other Items, Net

Dynegy’s other items, net totaled $49 million of income for the year ended December 31, 2007, compared to $54 million of income for the year ended December 31, 2006. The decrease was primarily associated with $7 million of minority interest expense related to the Plum Point facility as well as foreign currency losses in the year ended December 31, 2007. The minority interest expense was primarily due to the mark-to-market interest income recorded during the three months ended June 30, 2007 related to the interest rate swap agreements associated with the Plum Point Credit Agreement. Please read “—Interest Expense” below for further discussion.

DHI’s other items, net totaled $46 million of income for the year ended December 31, 2007, compared to $51 million of income for the year ended December 31, 2006. The decrease was primarily associated with $7 million of minority interest expense recorded in 2007 related to the Plum Point facility. The minority interest expense was primarily due to the mark-to-market interest income recorded during the three months ended June 30, 2007 related to the interest rate swap agreements associated with the Plum Point Credit Agreement. Please read “—Interest Expense” below for further discussion.

Interest Expense

Dynegy’s interest expense and debt conversion costs totaled $384 million for the year ended December 31, 2007, compared to $631 million for the year ended December 31, 2006. DHI’s interest expense and debt conversion costs totaled $384 million for the year ended December 31, 2007, compared to $579 million for the year ended December 31, 2006.

The decrease was primarily attributable to debt conversion costs and acceleration of financing costs resulting from our liability management program executed in the second quarter of 2006 as well as a $36 million charge associated with the Sithe Subordinated Debt exchange. Included in interest expense for the year ended December 31, 2007 was approximately $24 million of mark-to-market income from interest rate swap agreements associated with the Plum Point Credit Agreement Facility. Effective July 1, 2007, these agreements were designated as cash flow hedges. Also included in interest expense for the year ended December 31, 2007 was approximately $12 million of income from non-designated interest rate swap agreements that, prior to being terminated, were associated with the portion of the debt repaid in late May 2007. The mark-to-market income included in interest expense for 2007 was offset by net losses of approximately $7 million in connection with the repayment of a portion of the project indebtedness assumed in connection with the Merger. These items were offset by higher interest expense incurred in 2007 due to higher 2007 debt balances resulting from the Merger.

Income Tax (Expense) Benefit

Dynegy reported an income tax expense from continuing operations of $151 million for the year ended December 31, 2007, compared to an income tax benefit from continuing operations of $152 million for the year ended December 31, 2006. The 2007 effective tax rate was 57 percent, compared to 32 percent in 2006. The income tax expense in 2007 included a $4 million benefit resulting from the change in New York state tax law and a $3 million expense resulting from a net increase in tax reserves. Additionally, Dynegy realized a higher state income tax expense resulting from adjusting Dynegy’s temporary differences to a higher overall effective state tax rate. The higher effective state tax rate was driven by changes in levels of business activity in states in which we do business and the higher state tax rates in the states in which the LS Contributed Entities are located. Excluding the impact of changes in levels of business activity and changes in company structure, the 2007 calculation would result in an effective tax rate of 36 percent.

DHI reported an income tax expense from continuing operations of $116 million for the year ended December 31, 2007, compared to an income tax benefit from continuing operations of $125 million for the year ended December 31, 2006. The 2007 effective tax rate was 40 percent, compared to 30 percent in 2006. The income tax expense in 2007 included a $14 million benefit resulting from the change in New York state tax law and an $16 million benefit resulting from the release of tax reserves. Additionally, DHI realized a higher state income tax expense resulting from adjusting DHI’s temporary differences to a higher overall effective state tax rate. The higher effective state tax rate was driven by changes in levels of business activity in states in which we do business and the higher state tax rates in the states in which the LS Contributed Entities are located. Excluding the impact of changes in levels of business activity and changes in company structure, the 2007 calculation would result in an effective tax rate of 31 percent.

Discontinued Operations

Income From Discontinued Operations Before Taxes. Discontinued operations include the Calcasieu and CoGen Lyondell power generation facilities in our GEN-WE segment, DMSLP in our former NGL segment and our U.K. CRM business in the CRM segment.

During the year ended December 31, 2007, Dynegy’s pre-tax income from discontinued operations was $239 million ($148 million after-tax). Dynegy’s GEN-WE segment included $225 million from the operation of the CoGen Lyondell and Calcasieu power generation facilities, consisting primarily of a pre-tax gain of $224 million associated with the completion of our sale of the CoGen Lyondell power generation facility. Dynegy’s U.K. CRM business included income of $15 million, primarily related to a favorable settlement of a legacy receivable.

During the year ended December 31, 2006, Dynegy’s pre-tax loss from discontinued operations was $23 million ($13 million after-tax). Dynegy’s GEN-WE segment included losses of $53 million from the operation of the CoGen Lyondell and Calcasieu power generation facilities. The loss includes a $36 million impairment associated with the Calcasieu power generation facility. Dynegy’s U.K. CRM segment included earnings of $23 million for the year ended December 31, 2006, primarily related to a favorable settlement of a legacy receivable. Dynegy also recorded pre-tax income of $6 million attributable to NGL.

During the year ended December 31, 2007, DHI’s pre-tax income from discontinued operations was $240 million ($148 million after-tax). DHI’s GEN-WE segment included $225 million from the operation of the CoGen Lyondell and Calcasieu power generation facilities, consisting primarily of a pre-tax gain of $224 million associated with the completion of our sale of the CoGen Lyondell power generation facility. DHI’s U.K. CRM business included income of $15 million, primarily related to a favorable settlement of a legacy receivable.

During the year ended December 31, 2006, DHI’s pre-tax loss from discontinued operations was $24 million ($12 million after-tax). DHI’s GEN-WE segment included losses of $53 million from the operation of the CoGen Lyondell and Calcasieu power generation facilities. The loss includes a $36 million impairment associated with the Calcasieu power generation facility. DHI’s U.K. CRM segment included earnings of $23 million for the year ended December 31, 2006, primarily related to a favorable settlement of a legacy receivable. DHI also recorded pre-tax income of $6 million attributable to NGL.

Income Tax (Expense) Benefit From Discontinued Operations

Dynegy recorded an income tax expense from discontinued operations of $91 million during the year ended December 31, 2007, compared to an income tax benefit from discontinued operations of $10 million during the year ended December 31, 2006. The income tax expense in 2007 included a $9 million benefit from a net release of tax reserves. The effective tax rate was impacted by the $47 million of goodwill allocated to the CoGen Lyondell power generation facility upon its sale. As there was no tax basis in the goodwill, there were no tax benefits associated with the allocated goodwill.

DHI recorded an income tax expense from discontinued operations of $92 million during the year ended December 31, 2007, compared to an income tax benefit from discontinued operations of $12 million during the year ended December 31, 2006. The income tax expense in 2007 included an $8 million benefit from a net release of tax reserves. The effective tax rate for 2007 was impacted by the $47 million of goodwill allocated to the CoGen Lyondell power generation facility upon its sale. As there was no tax basis in the goodwill, there were no tax benefits associated with the allocated goodwill.

Cumulative Effect of Change in Accounting Principles

On January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123(R)). In connection with its adoption, Dynegy realized a cumulative effect loss of approximately $1 million, net of tax expense of zero. Please read Note 2—Summary of Significant Accounting Policies—Employee Stock Options for further information.

Year Ended 2006 Compared to Year Ended 2005

Operating Income (Loss)

Operating income for Dynegy was $105 million for the year ended December 31, 2006, compared to an operating loss of $832 million for the year ended December 31, 2005. Operating income for DHI was $108 million for the year ended December 31, 2006, compared to an operating loss of $733 million for the year ended December 31, 2005.

Power Generation—Midwest Segment. Operating income for GEN-MW was $208 million for the year ended December 31, 2006 for both Dynegy and DHI, compared to $194 million for Dynegy and $199 million for DHI for the year ended December 31, 2005. GEN-MW results for 2006 include a $110 million pre-tax impairment associated with our Bluegrass facility. GEN-MW results for 2005 include a $29 million pre-tax charge associated with the impairment of a natural gas turbine, which was sold in 2006. GEN-MW results for the year ended December 31, 2005 also included general and administrative expenses of $33 million. Beginning in 2006, general and administrative expenses are reported in Other and Eliminations. Please read “Results of Operations—Year Ended 2006 Compared to Year Ended 2005—Operating Income (Loss)—Other” for a consolidated discussion of general and administrative expenses.

Results from our coal-fired generating units increased from $415 million for the year ended December 31, 2005 to $466 million for 2006. Average actual on-peak prices in the CinHub/Cinergy pricing region decreased from $64 per MWh in the year ended December 31, 2005 to $52 per MWh for the year ended December 31, 2006. Generated volumes decreased from 21.9 million MWh in the year ended December 31, 2005 to 21.5 million MWh in the same period in 2006. Despite the decrease in market prices and the decrease in output, the increase in results was primarily driven by higher realized power prices. We realized higher power prices in the first quarter 2006 as we settled forward power sales. Additionally, results from our coal-fired generating units were negatively impacted by the Ameren contract during the second and third quarters of 2005, preventing us from recognizing the full benefit of market prices during the 2005 period. During certain peak periods in 2005, Ameren took higher volumes than we expected, resulting in a need to purchase power at market prices in order to satisfy our obligations for forward sales previously made to other third-parties. We did not experience a similar

situation under the Ameren contract in 2006. This was offset by mark-to-market income of approximately $14 million for the year ended December 31, 2006, compared with mark-to-market income of $23 million for the year ended December 31, 2005. These transactions are primarily related to options and other financial transactions that economically hedged our generation assets but were not designated as cash flow hedges. The higher realized prices were also partially offset by higher operating costs due to the timing of scheduled maintenance.

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

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

Power Generation—West Segment. Dynegy’s operating loss for GEN-WE was $2 million for the year ended December 31, 2006, compared to an operating loss of $15 million for the year ended December 31, 2005. DHI’s operating loss for GEN-WE was $2 million for the year ended December 31, 2006, compared to an operating loss of $16 million for the year ended December 31, 2005. GEN-SO results for 2006 include a $9 million impairment of our Rockingham facility as a result of the sale of the facility. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Rockingham for further discussion. GEN-SO results for the year ended December 31, 2005 also included general and administrative expenses of $11 million. Beginning in 2006, general and administrative expenses are reported in Other and Eliminations. Please read “Results of Operations—Year Ended 2006 Compared to Year Ended 2005—Operating Income (Loss)—Other” for a consolidated discussion of general and administrative expenses.

Results from our other West assets increased from $7 million in 2005 to $15 million in 2006, primarily as a result of increased volumes and pricing for our peaking facilities.

Depreciation expense was $8 million in 2006 compared to $11 million in 2005.

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

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

Independence contributed results of $46 million for the year ended December 31, 2006, compared with $18 million for the period from February through December 2005. Average on-peak prices for Zone A decreased

from $76 per MWh in 2005 to $59 per MWh in 2006. Generated volumes decreased from 2.3 million MWh in 2005 to 1.7 million MWh in 2006. Although market prices and generated volumes from our Independence facility decreased year over year, we received a benefit from the realization of higher power prices in the first half of 2006, as we settled forward power sales. Results for 2006 also reflect the benefit of increased capacity payments in the merchant market.

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

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

•

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

•

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

•

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

•

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

•

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

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

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

Dynegy’s consolidated general and administrative expenses, including those reported in its CRM segment, decreased from $468 million for 2005 to $196 million for 2006. General and administrative expenses for 2005 included a $236 million charge associated with settlement of our shareholder class action litigation and other legal and settlement charges totaling $51 million, while 2006 included $53 million in legal and settlement charges. Additionally, compensation and benefits costs and professional and legal fees were lower in 2006 compared to 2005.

DHI’s other operating loss was $160 million for 2006, compared to $298 million for 2005. Results for 2006 include approximately $140 million of general and administrative expenses, including costs related to our business segments, which prior to 2006 were included in the individual segments. Results for 2005 included general and administrative expenses of $269 million.

DHI’s consolidated general and administrative expenses, including those reported in its CRM segment, decreased from $375 million for 2005 to $193 million for 2006. General and administrative expenses for 2005 included a $154 million charge associated with

settlement of our shareholder class action litigation and other legal settlement charges totaling $38 million, while 2006 included $53 million in legal and settlement charges. Additionally, compensation and benefits costs and professional and legal fees were lower in 2006 compared to 2005.

Earnings from Unconsolidated Investments

The loss from unconsolidated investments of $1 million for 2006 was primarily related to the GEN-WE investment in Black Mountain. During 2006, we recorded equity earnings of $8 million related to our investment in Black Mountain offset by a $9 million impairment charge. This charge is the result of a decline in value of the investment related to the high cost of fuel in relation to a third party power purchase agreement through 2023 for 100 percent of the output of the facility. This agreement provides that Black Mountain will receive payments that decrease over time.

Dynegy’s earnings from unconsolidated investments of $2 million and DHI’s earnings from unconsolidated investments of zero for 2005 included $7 million earnings from the GEN-MW investment in Rocky Road, largely offset by results from GEN-WE investments in both Black Mountain and West Coast Power.

Other Items, Net

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

DHI’s other items, net totaled $51 million of income for 2006, compared to $15 million of income for 2005. The increase was primarily associated with higher interest income in 2006 resulting from higher cash balances and higher interest rates.

Interest Expense

Dynegy’s interest expense and debt conversion costs totaled $631 million for 2006, compared to $389 million for 2005. The increase was primarily due to debt conversion costs and acceleration of financing costs, as well as a $36 million charge associated with the Sithe Subordinated Debt exchange. These charges were partially offset by reductions due to lower principal amounts outstanding as a result of our liability management program. Please read Note 15—Debt for further discussion.

DHI’s interest expense and debt conversion costs totaled $579 million for 2006, compared to $383 million for 2005. The increase was primarily due to debt conversion costs and acceleration of financing costs, as well as a $36 million charge associated with the Sithe Subordinated Debt exchange. These charges were partially offset by reductions due to lower principal amounts outstanding as a result of our liability management program. Please read Note 15—Debt for further discussion.

Income Tax Benefit

Dynegy’s income tax benefit from continuing operations was $152 million in 2006, compared to an income tax benefit from continuing operations of $393 million in 2005. The 2006 effective tax rate was 32 percent, compared to 33 percent in 2005. The 2006 tax benefit included a $29 million expense related to various adjustments anticipated as a result of the Canadian authorities’ audit of prior year income tax returns. The 2005 tax benefit included an $18 million expense and a $13 million expense related to an increase in the valuation allowance associated with capital losses and foreign NOLs, respectively. Excluding these items from the 2006 and 2005 calculations would result in effective tax rates of 38 percent and 36 percent in 2006 and 2005, respectively.

DHI’s income tax benefit from continuing operations was $125 million in 2006, compared to an income tax benefit from continuing operations of $374 million in 2005. The 2006 effective tax rate was 30 percent, compared to 34 percent in 2005. The 2006 tax benefit included a $29 million expense related to various adjustments anticipated as a result of the Canadian authorities’ audit of prior year income tax returns. The 2005 tax benefit included a $14 million expense related to an increase in the valuation allowance associated with foreign NOLs, respectively. Excluding these items from the 2006 and 2005 calculations would result in effective tax rates of 37 percent and 35 percent in 2006 and 2005, respectively.

In general, differences between these adjusted effective rates and the statutory rate of 35 percent result primarily from the effect of certain foreign and state income taxes and permanent differences attributable to book-tax basis differences. Please read Note 17—Income Taxes for further discussion of our income taxes.

Discontinued Operations

The following summarizes Dynegy’s activity included in income from discontinued operations:

Year Ended December 31, 2006


	GEN-WE			U.K. CRM			DGC		NGL		Total
	(in millions)
Operating income (loss) included in income from discontinued operations	$	(53	)	$	18		$	—	$	6	$	(29	)
Other items, net included in income from discontinued operations		—			5			1		—		6

Loss from discontinued operations before taxes						</