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
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”).
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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.
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PART I
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.
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
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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.
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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. |
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| (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.
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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
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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
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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.
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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”).
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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
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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.
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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
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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
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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.
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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, NOx 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 NOx 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 NOx 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 NOx control program is in 2009; the SO2 control 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 NOx 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 NOx 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 NOx emissions from electric generators by setting aside 30 percent of the available NOx 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
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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 NOX, 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 | ||||
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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
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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.
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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.
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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.
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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.
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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
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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
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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.
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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
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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; |
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| • | 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; |
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| • | 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.
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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
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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; |
29
| • | 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.
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.
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.
30
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.
31
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:
| 1. | $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. |
32
| 2. | 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. |
| 3. | 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.
| * | $100 invested on 12/31/02 in stock or index-including reinvestment of dividends. Fiscal year ending December 31. |
Copyright © 2008, Standard & Poor’s, a division of The McGraw-Hill Companies, Inc. All rights reserved. www.researchdatagroup.com/S&P.htm
| 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 |
33
The stock price performance included in this graph is not necessarily indicative of future stock price performance.
The above stock price performance comparison and related discussion is not to be deemed incorporated by reference by any general statement incorporating by reference this Form 10-K into any filing under the Securities Act of 1933 or under the Securities Exchange Act of 1934, or otherwise, except to the extent that we specifically incorporate this stock price performance comparison and related discussion by reference, and is not otherwise deemed “filed” under the Acts.
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 | ||||||||||||||
34
| 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. |
35
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). |
36
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 |
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| 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. |
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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 CO2 emissions 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
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(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.
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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.
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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. |
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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 | |||||
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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; |
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| • | $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
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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.
46
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. |
47
| (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.
48
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.
49
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 | ||||||||||||||||||||||
50
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 | ||||||||||||||||||||||
51
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 | ) | |||||||||||||||||||||
52
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 | |||
53
| 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. |
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| 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.
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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 |
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| 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 |
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| • | 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.
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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.
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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.
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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
61
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
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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
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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.
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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
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 our CRM segment. Dynegy’s discontinued operations also includes its former DGC segment.
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 |
(23 | ) | |||||||||||||||
| Income tax benefit |
10 | ||||||||||||||||
| Loss from discontinued operations |
$ | (13 | ) | ||||||||||||||
Year Ended December 31, 2005
| GEN-WE |
U.K. CRM |
NGL |
Total |
||||||||||||
| (in millions) | |||||||||||||||
| Operating income included in income from discontinued operations |
$ | (6 | ) | $ | — | $ | 1,320 | $ | 1,314 | ||||||
| Earnings from unconsolidated investments included in income from discontinued operations |
— | 5 | 5 | ||||||||||||
| Other items, net included in income from discontinued operations |
6 | (22 | ) | (16 | ) | ||||||||||
| Interest expense included in income from discontinued operations |
(53 | ) | |||||||||||||
| Income from discontinued operations before taxes |
1,250 | ||||||||||||||
| Income tax expense |
(355 | ) | |||||||||||||
| Income from discontinued operations |
$ | 895 | |||||||||||||
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The following summarizes DHI’s activity included in income from discontinued operations:
Year Ended December 31, 2006
| GEN-WE |
U.K. CRM |
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 | — | 5 | ||||||||||
| Loss from discontinued operations before taxes |
(24 | ) | ||||||||||||
| Income tax benefit |
12 | |||||||||||||
| Loss from discontinued operations |
$ | (12 | ) | |||||||||||
Year Ended December 31, 2005
| GEN-WE |
U.K. CRM |
NGL |
Total |
||||||||||||
| (in millions) | |||||||||||||||
| Operating income (loss) included in income from discontinued operations |
$ | (6 | ) | $ | — | $ | 1,320 | $ | 1,314 | ||||||
| Earnings from unconsolidated investments included in income from discontinued operations |
— | — | 5 | 5 | |||||||||||
| Other items, net included in income from discontinued operations |
— | 6 | (22 | ) | (16 | ) | |||||||||
| Interest expense included in income from discontinued operations |
(53 | ) | |||||||||||||
| Income from discontinued operations before taxes |
1,250 | ||||||||||||||
| Income tax expense |
(437 | ) | |||||||||||||
| Income from discontinued operations |
$ | 813 | |||||||||||||
In 2006, Dynegy’s pre-tax loss from discontinued operations of $23 million ($13 million after-tax) included $6 million in pre-tax income attributable to NGL, a pre-tax gain of $21 million primarily related to a favorable settlement of a legacy receivable in our U.K. CRM business and a pre-tax loss of $53 million associated with GEN-WE. The loss includes a $36 million impairment associated with the Calcasieu power generation facility. In 2005, Dynegy’s pre-tax income from discontinued operations of $1,250 million ($895 million after-tax) included $1,320 million in pre-tax income attributable to NGL. Included in NGL’s 2005 pre-tax income is a pre-tax gain on the sale of DMSLP of $1,087 million and income attributable to ten months of operations.
In 2006, DHI’s pre-tax loss from discontinued operations of $24 million ($12 million after-tax) included $6 million in pre-tax income attributable to NGL, a pre-tax gain of $21 million primarily related to a favorable settlement of a legacy in our U.K. CRM business, and a pre-tax loss of $53 million associated with GEN-WE. The loss includes a $36 million impairment associated with the Calcasieu power generation facility. In 2005, DHI’s pre-tax income from discontinued operations of $1,250 million ($813 million after-tax) included $1,250 million in pre-tax income attributable to NGL. Included in NGL’s 2005 pre-tax income is a pre-tax gain on the sale of DMSLP of $1,087 million and income attributable to ten months of operations.
In accordance with EITF Issue 87-24, “Allocation of Interest to Discontinued Operations”, we have allocated interest expense to discontinued operations associated with debt instruments that were required to be paid upon the sale of DMSLP. Interest expense included in income from discontinued operations, which includes interest incurred on our former term loan and our former Generation facility debt, totaled zero and $53 million during 2006 and 2005, respectively.
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Income Tax (Expense) Benefit From Discontinued Operations
Dynegy recorded an income tax benefit from discontinued operations of $10 million in 2006, compared to an income tax expense from discontinued operations of $355 million in 2005. The income tax expense in 2005 includes a $112 million benefit associated with reducing a valuation allowance related to its capital loss carryforward, which primarily related to its third quarter 2002 sale of Northern Natural Gas. Dynegy reduced the valuation allowance as a result of capital gains expected to be recognized from the sale of DMSLP. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Other Discontinued Operations—Natural Gas Liquids for further information regarding the sale. The effective tax rates for 2006 and 2005, adjusting for the reduction of the valuation allowance in 2005, are 43 percent and 37 percent, respectively.
DHI recorded an income tax benefit from discontinued operations of $12 million in 2006, compared to an income tax expense from discontinued operations of $437 million in 2005. The income tax expense in 2005 includes a $34 million benefit associated with reducing a valuation allowance related to its capital loss carryforward. DHI reduced the valuation allowance as a result of capital gains expected to be recognized from the sale of DMSLP. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Other Discontinued Operations—Natural Gas Liquids for further information regarding the sale. The effective tax rates for 2006 and 2005, adjusting for the reduction of the valuation allowance in 2005, are 50 percent and 38 percent, respectively.
Cumulative Effect of Change in Accounting Principles
On January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123(R)). In connection with its adoption, 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.
On December 31, 2005, we adopted FIN No. 47. In connection with its adoption, we realized a cumulative effect loss of approximately $5 million ($7 million pre-tax). Please read Note 2—Summary of Significant Accounting Policies—Asset Retirement Obligations for further information.
2008 Outlook
We expect that our future financial results will continue to reflect sensitivity to fuel and commodity prices, market structure and prices for electric energy, ancillary services and capacity, transportation and transmission logistics, weather conditions and IMA. Our commercial team actively manages commodity price risk associated with our unsold power production by trading in the forward markets that are correlated with our assets. We also participate in various regional auctions and bilateral opportunities.
A substantial portion of the output from our fleet of power generation facilities is contracted for the next twelve months. The remaining output from our facilities is available for other forward sales opportunities to capture attractive market prices when they are available. To the extent that we choose not to enter into forward sales, the gross margin from our assets is a function of price movements in the coal, natural gas, fuel oil, electric energy and capacity markets.
The following summarizes our outlook for our power generation business by reportable segment.
GEN-MW. We expect our results to continue to be impacted by power prices, fuel prices, fuel availability and operational performance.
For 2008, GEN-MW results will continue to be affected by the delivery obligations resulting from our participation in the Illinois resource procurement auction. The price we will receive under the auction contract
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through May 2008 is approximately $65/MWh. Under the auction contract, we assume increased costs and penalty risks associated with managing delivered power volumes. We anticipate that the revenues generated by our Midwest facilities will continue to benefit in 2008 from the implementation of contracts resulting from the auction and the sale of additional volumes into the MISO wholesale markets at prevailing market prices.
Another factor impacting our results in the Midwest will be the process implemented in Illinois for procurement of future power requirements. In October 2007, Commonwealth Edison (“ComEd”) and the Ameren Illinois Utilities filed their procurement plans for the period from June 2008 to May 2009. In December 2007, the ICC approved those plans with certain modifications. The ComEd procurement is anticipated to be completed by early March 2008 and the Ameren procurement is anticipated to occur in March or April 2008.
Our Midwest consent decree requires substantial emission reductions from our Illinois coal-fired power plants and the completion of several supplemental environmental projects in the Midwest. We have achieved all emission reductions scheduled to date under the Consent Decree and are developing plans to install additional emission control equipment to meet future Consent Decree emission limits. We have constructed a mercury control project at the Vermilion Power Station that began operation in June 2007. We expect our costs associated with the Midwest consent decree projects to increase. Please read “Environmental Matters—The Clean Air Act” for further discussion.
Our Midwest coal requirements are 100 percent contracted through 2010. For 2008, the prices associated with these contracts are fixed. Our longer term results are sensitive to changes in coal prices to the extent that our current fixed prices are adjusted through contract re-openers or related provisions. However, the amount by which prices can increase under a significant portion of these re-openers is capped. The new prices resulting from the re-openers will become effective January 1, 2009.
Our results will continue to be affected by IMA. We use IMA to monitor fleet performance over time. This measure quantifies the percentage of generation for each of our major steam units that were available when market prices were favorable for participation. Through our focus on safe and efficient operations, we seek to maximize our IMA and, as a result, our revenue generating opportunities. The IMA for our Midwest coal-fired fleet for the twelve months ended December 31, 2007 was approximately 93 percent compared to 89 percent for the comparable period of 2006. (In 2007, we modified the way we calculate IMA to better reflect the capabilities of the units due to seasonal variations. IMA for 2006 has been recalculated on a basis comparable to 2007.) In 2008, we will extend our IMA metric to our combined-cycle plants. We attempt to schedule maintenance and repair work to minimize downtime during peak demand periods, to the extent doing so does not compromise a safe working environment for our employees and contractors.
The Ontelaunee facility sells its energy, capacity and other ancillary services to wholesale electricity customers directly on the spot market. However, exposure to the market prices of energy has been hedged under a financially settled heat rate call-option agreement.
PJM recently implemented a forward capacity auction, the Reliability Pricing Model. The auction has resulted in a dramatic increase in the value of capacity in not only PJM, but in the neighboring MISO as well. The increase in prices indicates a projected tightening of the supply/demand balance in the near future. More immediately, we benefited from selling approximately 1,300 MWs net into the 2008-2009 planning year auction and 2,650 net MWs into the 2009-2010 auction, both of which were held in 2007.
Plum Point is currently in the construction phase, with an expected completion date of August 2010. Upon completion it will be a 665 MW coal-fired power generating facility located in Osceola, Arkansas. Our interest in the facility, after giving effect to minority interests and other undivided interests in the project, is approximately 140 MW. The City of Osceola has loaned $100 million in proceeds of a tax-exempt bond issuance to Plum Point.
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We are considering the possibility of refinancing the outstanding Tax Exempt Bonds, however any decision to proceed will be conditioned on seeking necessary public approvals and favorable market conditions. Please read Note 15—Debt—Plum Point Tax Exempt Bonds for further discussion.
GEN-WE. We expect our results to continue to be impacted by our ability to operate our generation facilities reliably so they are available to dispatch when called on. To the extent that our facilities are not contracted under tolling agreements, results will continue to be impacted by the spread between power and natural gas prices. Our GEN-WE segment will no longer benefit from the earnings from the CoGen Lyondell facility due to the completion of the sale of this facility on August 1, 2007. For the twelve months ended December 31, 2007, we recorded operating income of $11 million related to the operation of CoGen Lyondell. This amount has been reclassified as income from discontinued operations. Please read “—Liquidity and Capital Resources—External Liquidity Sources—Asset Sale Proceeds” for further discussion.
In August 2007, our GEN-WE segment acquired a 50 percent interest in SCEA, which owns a 75 percent undivided interest in the Sandy Creek Energy Station, a proposed 898 MW facility under construction in McLennan County, Texas. Please read Note 12—Variable Interest Entities—Sandy Creek for further discussion. SCEA intends to pursue opportunities to enter into long-term contacts for the generation from the facility, which we anticipate will begin commercial operations in 2012.
GEN-NE. We expect our results to continue to be impacted by power prices, fuel prices, fuel availability and IMA. Spreads between the price for power and fuel costs are expected to remain volatile as both fuel and power prices change based on demand and weather, which has significant impact on the run-time for the Roseton unit. The majority of our coal supply requirements for 2008 are contracted at a fixed price. We continue to maintain sufficient coal and oil inventories and contractual commitments intended to provide us with a stable fuel supply.
Additionally, our results could be affected by potential changes in New York, Maine and/or Connecticut state environmental regulations, as well as our ability to obtain permits necessary for the operation of our facilities. Please read Note 19—Commitments and Contingencies—Danskammer State Pollutant Discharge Elimination System Permit and—Commitments and Contingencies—Roseton State Pollutant Discharge Elimination System Permit, respectively, for further discussion.
DLS Power Development. Through Dynegy’s interest in DLS Power Development, Dynegy and LS Associates continue to move forward with the Long Leaf project, which comprises development of 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 Superior Court of Fulton County, Georgia. Management could seek construction financing and power purchase agreements for future generation from the facility during 2008.
The DLS Power Development portfolio, which includes projects in various stages of development that could rely on coal, natural gas or wind, is anticipated to be dynamic in nature. Changes in projects and priorities are 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 that they deem relevant.
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CASH FLOW DISCLOSURES
The following table includes data from the operating section of the consolidated statements of cash flows and includes cash flows from our discontinued operations, which are disclosed on a net basis in income from discontinued operations, net of tax expense, in the consolidated statements of operations:
| Dynegy Inc. |
Dynegy Holdings Inc. |
|||||||||||||||||||||||
| Years Ended December 31, |
Years Ended December 31, |
|||||||||||||||||||||||
| 2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
|||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||
| Operating cash flows from our generation businesses |
$ | 934 | $ | 698 | $ | 472 | $ | 934 | $ | 698 | $ | 472 | ||||||||||||
| Operating cash flows from our customer risk management business |
(30 | ) | (461 | ) | (21 | ) | (30 | ) | (461 | ) | (21 | ) | ||||||||||||
| Operating cash flows from our natural gas liquids business |
— | — | 288 | — | — | 288 | ||||||||||||||||||
| Other operating cash flows |
(563 | ) | (431 | ) | (769 | ) | (536 | ) | (442 | ) | (763 | ) | ||||||||||||
| Net cash provided by (used in) operating activities |
$ | 341 | $ | (194 | ) | $ | (30 | ) | $ | 368 | $ | (205 | ) | $ | (24 | ) | ||||||||
Operating Cash Flow
Dynegy. Dynegy’s cash flow provided by operations totaled $341 million for the twelve months ended December 31, 2007. During the period, our power generation business provided positive cash flow from operations of $934 million primarily due to positive earnings for the period, partly offset by an increased use of working capital. Our CRM business used approximately $30 million in cash primarily due to the payment of legal settlements and the purchase of gas in connection with certain legacy positions. Other included a use of approximately $563 million in cash primarily due to interest payments to service debt and general and administrative expenses.
Dynegy’s cash flow used in operations totaled $194 million for the twelve months ended December 31, 2006. During the period, our power generation business provided positive cash flow from operations of $698 million primarily due to positive earnings for the period, decreases in working capital due to returns of cash collateral postings and decreased accounts receivable balances. Our CRM business used approximately $461 million in cash primarily due to (i) a $370 million termination payment on our Sterlington tolling contract, (ii) a $44 million settlement payment to resolve claims relating to a former Master Netting Setoff Security Agreement with Enron, and (iii) a $37 million settlement of class action claims by California parties alleging price manipulation and false reporting of natural gas trades by our former gas trading business. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Sterlington Contract Termination for further information. Other included a use of approximately $431 million in cash primarily due to interest payments to service debt and general and administrative expenses, partially offset by interest income on cash balances and the receipt of approximately $20 million associated with the resolution of a legal dispute.
Dynegy’s cash flow used in operations totaled $30 million for the twelve months ended December 31, 2005. During the period, our power generation business provided positive cash flow from operations of $472 million, due primarily to positive earnings for the period as well as the return of cash collateral during 2005. This was offset by increased accounts receivable balances due to higher prices at December 31, 2005 as compared to December 31, 2004. Our customer risk management business had cash outflows of approximately $21 million, due primarily to fixed payments associated with the former Sterlington and Gregory power tolling arrangement and our final payment of $26 million related to our exit from four long-term natural gas transportation contracts. This was offset partially by the return of cash collateral during 2005. Our discontinued natural gas liquids business provided cash flow from operations of $288 million due primarily to positive earnings for the period as well as the return of cash collateral. Other included a use of approximately $769 million in cash due primarily to
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our payments of $255 million in connection with the settlement of the shareholder class action litigation, interest payments to service debt, pension plan contributions of approximately $31 million, state tax payments and general and administrative expenses.
DHI. DHI’s cash flow provided by operations totaled $368 million for the twelve months ended December 31, 2007. During the period, our power generation business provided positive cash flow from operations of $934 million primarily due to positive earnings for the period, partly offset by an increased use of working capital. Our CRM business used approximately $30 million in cash primarily due to the payment of legal settlements and the purchase of gas in connection with certain legacy positions. Other included a use of approximately $536 million in cash primarily due to interest payments to service debt and general and administrative expenses.
DHI’s cash flow used in operations totaled $205 million for the twelve months ended December 31, 2006. During the period, our power generation business provided positive cash flow from operations of $698 million primarily due to positive earnings for the period, increases in working capital due to returns of cash collateral postings and decreased accounts receivable balances. Our CRM business used approximately $461 million in cash primarily due to (i) a $370 million termination payment on our Sterlington tolling contract, (ii) a $44 million settlement payment to resolve claims relating to a former Master Netting Setoff Security Agreement with Enron, and (iii) a $37 million settlement of class action claims by California parties alleging price manipulation and false reporting of natural gas trades by our former gas trading business. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Sterlington Contract Termination for further information. Other included a use of approximately $442 million in cash primarily due to interest payments to service debt and general and administrative expenses, partially offset by interest income on cash balances.
DHI’s cash flow used in operations totaled $24 million for the twelve months ended December 31, 2005. During the period, our power generation business provided positive cash flow from operations of $472 million, due primarily to positive earnings for the period as well as the return of cash collateral during 2005. This was offset by increased accounts receivable balances due to higher prices at December 31, 2005 as compared to December 31, 2004. Our customer risk management business had cash outflows of approximately $21 million, due primarily to fixed payments associated with the former Sterlington and Gregory power tolling arrangement and our final payment of $26 million related to our exit from four long-term natural gas transportation contracts. Our discontinued natural gas liquids business provided cash flow from operations of $288 million due primarily to positive earnings for the period as well as the return of cash collateral. Other included a use of approximately $763 million in cash due primarily to our payments of $255 million in connection with the settlement of the shareholder class action litigation, interest payments to service debt, pension plan contributions of approximately $31 million, state tax payments and general and administrative expenses.
Capital Expenditures and Investing Activities
Dynegy. Dynegy’s cash used in investing activities during the twelve months ended December 31, 2007 totaled $817 million. Capital spending of $379 million was primarily comprised of $300 million, $17 million, and $47 million in the GEN-MW, GEN-WE, and GEN-NE segments, respectively. Capital spending in the GEN-MW segment included $161 million associated with the construction of the Plum Point facility. The remaining capital spending for the GEN-MW and GEN-WE segments primarily related to maintenance and environmental capital projects, while spending in the GEN-NE segment primarily related to maintenance. In addition, there was approximately $15 million of capital expenditures in Other.
Proceeds from asset sales totaled $558 million in 2007 and primarily consisted of $472 million from the sale of our CoGen Lyondell power generation facility and $82 million received in connection with the sale of a portion of our interest in the Plum Point Project. Please read Note 4—Dispositions, Contract Terminations and
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Discontinued Operations—GEN-WE Discontinued Operations—CoGen Lyondell and Note 4—Dispositions, Contract Terminations and Discontinued Operations— Dispositions and Contract Terminations—PPEA Holding Company LLC for more information. Proceeds from asset sales were partially offset by cash used in connection with the completion of the Merger, net of cash acquired, of $128 million. Please read Note 3—Business Combinations and Acquisitions—LS Power Business Combination for more information.
The increase in restricted cash and investments of $871 million during the twelve months ended December 31, 2007 related primarily to a $650 million deposit associated with our cash collateralized facility, and $323 million posted in support of our proportionate share of capital commitments in connection with the Sandy Creek Project. These additional postings were partially offset by the release of Independence restricted cash in exchange for the posting of a letter of credit.
Dynegy’s cash provided by investing activities during the twelve months ended December 31, 2006 totaled $358 million. Capital spending of $155 million was primarily comprised of $101 million, $24 million, and $22 million in the GEN-MW, GEN-WE, and GEN-NE segments, respectively. The capital spending for each segment primarily related to maintenance and environmental capital projects. In addition, there was approximately $8 million of capital expenditures in Other.
Proceeds from the exchange of unconsolidated investments, net of cash acquired, totaled $165 million in 2006. This included net cash proceeds of $205 million from the sale of our 50 percent ownership interest in West Coast Power to NRG. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—West Coast Power for further information. This was partially offset by a payment of $45 million for our acquisition of NRG’s 50 percent ownership interest in Rocky Road, which included $5 million of cash on hand. Please read Note 3—Business Combinations and Acquisitions—Rocky Road for more information.
Proceeds from asset sales, net, totaled $227 million during the twelve months ended December 31, 2006 and primarily consisted of proceeds from the sale of our Rockingham facility for $194 million. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Rockingham for more information. In addition, we received proceeds of $15 million associated with the 2005 sale of our natural gas liquids business. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Other Discontinued Operations—Natural Gas Liquids for more information. We also received proceeds of $14 million associated with the sale of a natural gas turbine that was not in use.
The decrease in restricted cash of $121 million in 2006 related primarily to the return of our $335 million deposit associated with our former cash collateralized facility, offset by a $200 million deposit associated with our new cash collateralized facility and a $14 million increase in the Independence restricted cash balance.
Dynegy’s cash provided by investing activities during the twelve months ended December 31, 2005 totaled $1,824 million. Capital spending of $195 million was primarily comprised of $113 million, $9 million, $21 million and $45 million in the GEN-MW, GEN-WE, GEN-NE and NGL segments, respectively. The capital spending for our GEN-MW segment primarily related to capital maintenance projects, as well as $17 million and $10 million in development capital associated with the completion of the Vermilion and Havana PRB conversions, respectively. Capital spending for our GEN-WE and GEN-NE segments primarily related to maintenance and environmental projects. Capital spending in our NGL segment primarily related to capital maintenance projects and wellconnects.
The cost to acquire Sithe Energies, net of cash proceeds, totaled $120 million. The increase in restricted cash of $353 million related primarily to a $335 million deposit associated with our cash collateralized facility, as well as an $18 million increase in the Independence restricted cash balance.
Net cash proceeds from asset sales of $2,488 million consisted of the following items:
| • | $2,382 million, net of transaction costs, from the sale of DMSLP; |
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| • | a $100 million return of funds held in escrow, offset by a $5 million payment to Ameren associated with a working capital adjustment, both of which related to the 2004 sale of Illinois Power; and |
| • | $10 million from the sale of land at our Port Everglades facility. |
DHI. DHI’s cash used in investing activities during the twelve months ended December 31, 2007 totaled $688 million. Capital spending of $379 million was primarily comprised of $300 million, $17 million, and $47 million in the GEN-MW, GEN-WE, and GEN-NE segments, respectively. Capital spending in the GEN-MW segment includes $161 million associated with the construction of the Plum Point facility. The remaining capital spending for the GEN-MW and GEN-WE segments primarily related to maintenance and environmental capital projects, while spending in the GEN-NE segment primarily related to maintenance. In addition, there was approximately $15 million of capital expenditures in Other.
Proceeds from assets sales totaled $558 million in 2007 and primarily consisted of $472 million from the sale of our CoGen Lyondell power generation facility and $82 million received in connection with the sale of a portion of our interest in the Plum Point Project. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—GEN-WE Discontinues Operations—CoGen Lyondell and Note 4—Dispositions, Contract Terminations and Discontinued Operations— Dispositions and Contract Terminations—PPEA Holding Company LLC for more information.
The increase in restricted cash and investments of $871 million related primarily to a $650 million deposit associated with our cash collateralized facility, and $323 million posted in support of our proportionate share of capital commitments in connection with the Sandy Creek Project. These additional postings were partially offset by the release of Independence restricted cash in exchange for the posting of a letter of credit.
DHI’s cash provided by investing activities during the twelve months ended December 31, 2006 totaled $357 million. Capital spending of $155 million was primarily comprised of $101 million, $24 million and $22 million in the GEN-MW, GEN-WE, and GEN-NE segments, respectively. The capital spending for each segment primarily related to maintenance and environmental capital projects. In addition, there was approximately $8 million of capital expenditures in the Other segment.
Proceeds from the exchange of unconsolidated investments, net of cash acquired, totaled $165 million. This included net cash proceeds of $205 million from the sale of our 50 percent ownership interest in West Coast Power to NRG. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—West Coast Power for further information. This was partially offset by a payment of $45 million for our acquisition of NRG’s 50 percent ownership interest in Rocky Road, which included $5 million of cash on hand. Please read Note 3—Business Combinations and Acquisitions—Rocky Road for more information.
Proceeds from asset sales, net totaled $224 million in 2006 and primarily consisted of proceeds from the sale of our Rockingham facility for $194 million. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Rockingham for more information. In addition, we received proceeds of $15 million associated with the 2005 sale of our natural gas liquids business. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Other Discontinued Operations—Natural Gas Liquids for more information. We also received proceeds of $14 million associated with the sale of a natural gas turbine that was not in use.
The decrease in restricted cash of $121 million related primarily to the return of our $335 million deposit associated with our former cash collateralized facility, offset by a $200 million deposit associated with our new cash collateralized facility and a $14 million increase in the Independence restricted cash balance.
DHI’s cash provided by investing activities during the twelve months ended December 31, 2005 totaled $1,839 million. Capital spending of $195 million was primarily comprised of $113 million, $9 million,
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$21 million and $45 million in the GEN-MW, GEN-WE, GEN-NE and NGL segments, respectively. The capital spending for our GEN-MW segment primarily related to capital maintenance projects, as well as $17 million and $10 million in development capital associated with the completion of the Vermilion and Havana PRB conversions, respectively. Capital spending for our GEN-WE and GEN-NE segments primarily related to maintenance and environmental projects. Capital spending in our NGL segment primarily related to capital maintenance projects and wellconnects.
In connection with Dynegy’s contribution of New York holdings to DHI, DHI acquired a cash balance of $26 million. The increase in restricted cash related to a $335 million deposit associated with our cash collateralized facility as well as an $18 million increase in the Independence restricted cash balance.
Net cash proceeds from asset sales of $2,393 million consisted of the following items:
| • | $2,382 million, net of transaction costs, from the sale of DMSLP; and |
| • | $10 million from the sale of land at our Port Everglades facility. |
Financing Activities
Dynegy. Dynegy’s cash provided by financing activities during the twelve months ended December 31, 2007 totaled $433 million. During the twelve months ended December 31, 2007, Dynegy received proceeds from long-term borrowings from the following sources, net of approximately $35 million of debt issuance costs:
| • | $1,650 million from our Senior Unsecured Notes due 2015 and 2019; |
| • | $665 million on our letter of credit facilities; |
| • | $275 million on our revolver due 2012; |
| • | $70 million on our senior secured term loan facility due 2013; and |
| • | $133 million on our Plum Point Credit Agreement Facility. |
These borrowings were partially offset by $2,320 million of payments:
| • | $396 million on our Kendall Senior Secured Term Loan Facility; |
| • | $150 million on our Ontelaunee term loan due 2009; |
| • | $919 million on our Gen Finance First Lien Term Loan; |
| • | $150 million on our Gen Finance Second Lien Term Loan; |
| • | $275 million on our promissory note to LS Associates; |
| • | $275 million on our Revolving Facility; |
| • | $70 million on our Griffith debt; |
| • | $39 million on our 8.50 percent secured bonds due 2007; |
| • | $20 million on our 9.00 percent secured bonds due 2013; |
| • | $15 million on our letter of credit facilities; and |
| • | $11 million on our Second Priority Senior Secured Notes. |
Dynegy’s cash used in financing activities during the twelve months ended December 31, 2006 totaled $1,342 million. Repayments of long-term debt totaled $1,930 million and consisted of the following:
| • | $900 million on our 10.125 percent Second Priority Senior Secured Notes due 2013; |
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| • | $614 million on our 9.875 percent Second Priority Senior Secured Notes due 2010; |
| • | $225 million on our Second Priority Senior Secured Floating Rate Notes due 2008; |
| • | $150 million on our Term Loan; |
| • | $23 million on our 7.45 percent Senior Notes due 2006; and |
| • | $18 million on our 8.50 percent secured bonds due 2007. |
Debt conversion costs of $249 million consisted of the following:
| • | $204 million to redeem the Second Priority Senior Secured Notes mentioned above, including approximately $3 million of transaction costs; |
| • | $44 million aggregate premium to induce conversion of our $225 million 4.75 percent Convertible Subordinated Debentures due 2023; and |
| • | $1 million in transaction costs associated with the redemption of our Series C Preferred. |
The repayments were partially offset by $1,071 million of proceeds from the following sources, net of approximately $29 million of debt issuance costs:
| • | $750 million from a private offering of our 8.375 percent Senior Unsecured Notes due 2016; |
| • | $200 million from the letter of credit facility due 2012; and |
| • | $150 million from the term loan due 2012. |
Dynegy paid CUSA $400 million in cash, plus accrued and unpaid dividends totaling approximately $6.3 million, to redeem the Series C Preferred in May 2006. Proceeds from the issuance of common stock consisted primarily of approximately $178 million from a public offering of 40.25 million shares of our Class A common stock at $4.60 per share, net of underwriting fees. Dividend payments totaling $17 million were also made on our Series C Preferred prior to its redemption.
Dynegy’s cash used in financing activities during the twelve months ended December 31, 2005 totaled $873 million. Repayments of long-term debt totaled $1,432 million and consisted of the following:
| • | $600 million on a revolver due May 2007; |
| • | $597 million on the term loan; |
| • | $183 million on the Riverside facility debt; |
| • | $34 million on the Independence Senior Notes due 2007; and |
| • | $18 million on a maturing series of DHI senior notes. |
The repayments were partially offset by proceeds from the October 2005 draw-down on the $600 million aggregate principal outstanding revolver due May 2007. Cash used in financing activities also included semi-annual dividend payments totaling $22 million on our Series C Preferred and distributions of $25 million to minority interest owners.
DHI. DHI’s cash provided by financing activities during the twelve months ended December 31, 2007 totaled $369 million. During the twelve months ended December 31, 2007, Dynegy received proceeds from long-term borrowings from the following sources, net of approximately $35 million of debt issuance costs:
| • | $1,650 million from our Senior Unsecured Notes due 2015 and 2019; |
| • | $665 million on our letter of credit facilities; |
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| • | $275 million on our revolver due 2012; |
| • | $70 million on our senior secured term loan facility due 2013; and |
| • | $133 million on our Plum Point Credit Agreement Facility. |
These borrowings were partially offset by $2,045 million of payments:
| • | $396 million on our Kendall Senior Secured Term Loan Facility; |
| • | $150 million on our Ontelaunee term loan due 2009; |
| • | $919 million on our Gen Finance First Lien Term Loan; |
| • | $150 million on our Gen Finance Second Lien Term Loan; |
| • | $275 million on our Revolving Facility; |
| • | $70 million on our Griffith debt; |
| • | $39 million on our 8.50 percent secured bonds due 2007; |
| • | $20 million on our 9.00 percent secured bonds due 2013; |
| • | $15 million on our letter of credit facilities; and |
| • | $11 million on our Second Priority Senior Secured Notes. |
Cash used in financing activities includes dividend payments of $342 million to Dynegy.
DHI’s cash used in financing activities during the twelve months ended December 31, 2006 totaled $1,235 million. Repayments of long-term debt totaled $1,930 million and consisted of the following:
| • | $900 million on our 10.125 percent Second Priority Senior Secured Notes due 2013; |
| • | $614 million on our 9.875 percent Second Priority Senior Secured Notes due 2010; |
| • | $225 million on our Second Priority Senior Secured Floating Rate Notes due 2008; |
| • | $150 million on our Term Loan; |
| • | $23 million on our 7.45 percent Senior Notes due 2006; and |
| • | $18 million on our 8.50 percent secured bonds due 2007. |
Debt conversion costs of $204 million consisted of the following:
| • | $204 million to redeem the Second Priority Senior Secured Notes mentioned above, including approximately $3 million of transaction costs. |
The repayments were partially offset by $1,071 million of proceeds from the following sources, net of approximately $29 million of debt issuance costs:
| • | $750 million from a private offering of our 8.375 percent Senior Unsecured Notes due 2016; |
| • | $200 million from the letter of credit facility due 2012; and |
| • | $150 million from the term loan due 2012. |
Cash used in financing activities includes $170 million in payments to Dynegy, which consists of repayments of borrowings of $120 million and a one time dividend payment of $50 million.
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DHI’s cash used in financing activities during the twelve months ended December 31, 2005 totaled $734 million. Repayments of long-term debt totaled $1,432 million and consisted of the following:
| • | $600 million on a revolver due May 2007; |
| • | $597 million on the term loan; |
| • | $183 million on the Riverside facility debt; |
| • | $34 million on the Independence Senior Notes due 2007; and |
| • | $18 million on a maturing series of DHI senior notes. |
The repayments were partially offset by proceeds from the October 2005 draw-down on the $600 million aggregate principal outstanding revolver due May 2007.
Net borrowings from affiliates totaled $120 million during the year ended December 31, 2005.
SEASONALITY
Our revenues and operating income are subject to fluctuations during the year, primarily due to the impact seasonal factors have on sales volumes and the prices of power and natural gas. Power marketing operations and generating facilities have higher volatility and demand, respectively, in the summer cooling months. This trend may change over time as demand for natural gas increases in the summer months as a result of increased natural gas-fired electricity generation.
CRITICAL ACCOUNTING POLICIES
Our Accounting Department is responsible for the development and application of accounting policy and control procedures. This department conducts these activities independent of any active management of our risk exposures, is independent of our business segments and reports to the Chief Financial Officer.
The process of preparing financial statements in accordance with GAAP requires our management to make estimates and judgments. It is possible that materially different amounts could be recorded if these estimates and judgments change or if actual results differ from these estimates and judgments. We have identified the following seven critical accounting policies that require a significant amount of estimation and judgment and are considered important to the portrayal of our financial position and results of operations:
| • | Revenue Recognition and Valuation of Risk Management Assets and Liabilities; |
| • | Valuation of Tangible and Intangible Assets; |
| • | Accounting for Contingencies, Guarantees and Indemnifications; |
| • | Accounting for Asset Retirement Obligations; |
| • | Accounting for Variable Interest Entities; |
| • | Accounting for Income Taxes; and |
| • | Valuation of Pension and Other Post-Retirement Plans Assets and Liabilities. |
Revenue Recognition and Valuation of Risk Management Assets and Liabilities
We earn revenue from our facilities in three primary ways: (i) sale of energy generated by our facilities; (ii) sale of ancillary services, which are the products of a generation facility that support the transmission grid
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operation, allow generation to follow real-time changes in load, and provide emergency reserves for major changes to the balance of generation and load; and (iii) sale of capacity. We recognize revenue from these transactions when the product or service is delivered to a customer, unless they meet the definition of a derivative, as defined by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended, (“SFAS No. 133”). Please read “Derivative Instruments—Generation” for further discussion of the accounting for these types of transactions.
Derivative Instruments—Generation. We enter into commodity contracts that meet the definition of a derivative under SFAS No. 133. These contracts are often entered into to mitigate or eliminate market and financial risks associated with our generation business. These contracts include power sales contracts, fuel purchase contracts, heat rate call options, and other instruments used to mitigate variability in earnings due to fluctuations in market prices. SFAS No. 133 proscribes three different ways to account for these types of contracts: (i) as an accrual contract, if the criteria for the “normal purchase normal sale” exception are met and documented; (ii) as a cash flow or fair value hedge, if the criteria are met and documented; or (iii) as a mark-to-market contract with changes in fair value recognized in current period earnings. All derivative commodity contracts that do not qualify for the “normal purchase normal sale” exception are recorded at fair value in risk management assets and liabilities on the consolidated balance sheets. If the derivative commodity contract has been designated as a cash flow hedge, the changes in fair value are recognized in earnings concurrent with the hedged item. Changes in the fair value of derivative commodity contracts that are not designated as cash flow hedges are recorded currently in earnings. Because derivative contracts can be accounted for in three different ways, and as the “normal purchase normal sale” exception and cash flow and fair value hedge accounting are elective, the accounting treatment used by another party for a similar transaction could be different from the accounting treatment we use. To the extent a party elects to apply cash flow hedge accounting for qualifying transactions, there is generally less volatility in the income statement as a portion of the changes in the fair values of the derivative instruments is recognized through equity.
In order to estimate the fair value of our derivative contracts, we use a liquidation value approach and assume that the ability to transact business in the market remains at historical levels. The estimated fair value of the portfolio is computed by multiplying all existing positions in the portfolio by estimated prices, reduced by a time value of money adjustment and reserves for credit and price risk. The estimated prices in this valuation are based either on (i) prices obtained from market quotes, when there are an adequate number of quotes to consider the period liquid, or, (ii) if market quotes are unavailable or the market is not considered liquid, prices from a proprietary model which incorporates forward energy prices derived from market quotes and values from previously executed transactions. The amounts recorded as revenue change as these estimates are revised to reflect actual results and changes in market conditions or other factors, many of which are beyond our control. Volatility in commodity prices, interest rates and, if applicable, foreign exchange rates, can significantly impact the valuation of these derivative contracts.
Derivative Instruments—Financing Activities. We are exposed to changes in interest rate risk through our variable and fixed rate debt. In order to manage our interest rate risk, we enter into interest rate swap agreements that meet the definition of a derivative under SFAS No. 133. SFAS No. 133 requires us to mark-to-market all derivative instruments on the balance sheet. If the derivative is designated as a cash flow hedge, the changes in the fair value of the derivative are recorded in OCI and the realized gains and losses related to these derivatives are recognized in earnings in the same period as the settlement of the underlying hedged transaction. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized currently in earnings. If the derivative is not designated as a hedge, the change in value is recognized currently in earnings. To the extent a party elects to apply hedge accounting for qualifying transactions, there is generally less volatility in the income statement.
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Valuation of Tangible and Intangible Assets
We evaluate long-lived assets, such as property, plant and equipment and investments, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Factors we consider important, which could trigger an impairment analysis, include, among others:
| • | significant underperformance relative to historical or projected future operating results; |
| • | significant changes in the manner of our use of the assets or the strategy for our overall business; |
| • | significant negative industry or economic trends; and |
| • | significant declines in stock value for a sustained period. |
We assess the carrying value of our property, plant and equipment and intangible assets subject to amortization in accordance with SFAS No. 144. If an impairment is indicated, the amount of the impairment loss recognized would be determined by the amount the book value exceeds the estimated fair value of the assets. The estimated fair value may include estimates based upon discounted cash-flow projections, recent comparable market transactions or quoted prices to determine if an impairment loss is required. For assets identified as held for sale, the book value is compared to the estimated sales price less costs to sell. There is a significant amount of judgment involved in cash-flow estimates, including assumptions regarding market convergence, discount rates and capacity. The assumptions used by another party could differ significantly from our assumptions. Please read Note 5—Restructuring and Impairment Charges for discussion of impairment charges we recognized in 2006 and 2005.
We follow the guidance of APB 18, “The Equity Method of Accounting for Investments in Common Stock” (“APB 18”), SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (“SFAS No. 115”), and EITF Issue 02-14, “Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock” (“EITF 02-14”), when reviewing our investments. The book value of the investment is compared to the estimated fair value, based either on discounted cash flow projections or estimated market prices, if available, to determine if an impairment is required. We record a loss when the decline in value is considered other than temporary.
We assess the carrying value of our goodwill in accordance with SFAS No. 142. Our goodwill test is performed annually on November 1 and when circumstances warrant. There is a significant amount of judgment in the determination of the fair value of our reporting units, including assumptions around market convergence, discount rates, capacity and growth rates.
Our assessments regarding valuation of tangible and intangible assets are subject to estimates and judgment of management. Market conditions, energy prices, estimated useful lives of the assets, discount rate assumptions and legal factors impacting our business may have a significant effect on the estimates. If different judgments were applied, estimates could differ significantly. Actual results could vary materially from these estimates.
Please read Note 13—Goodwill and Note 14—Intangible Assets for further discussion of our accounting for goodwill and intangible assets.
Accounting for Contingencies, Guarantees and Indemnifications
We are involved in numerous lawsuits, claims, proceedings, and tax-related audits in the normal course of our operations. In accordance with SFAS No. 5, “Accounting for Contingencies” (“SFAS No. 5”), we record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss contingencies on an ongoing basis to ensure that we have appropriate reserves recorded on our consolidated balance sheets as required by SFAS No. 5. These reserves are based on estimates and judgments made by management with respect to the likely outcome of these matters,
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considering any applicable insurance coverage for litigation matters, and are adjusted as circumstances warrant. Our estimates and judgments could change based on new information, changes in laws or regulations, changes in management’s plans or intentions, the outcome of legal proceedings, settlements or other factors. If different estimates and judgments were applied with respect to these matters, it is likely that reserves would be recorded for different amounts. Actual results could vary materially from these reserves.
Liabilities are recorded when an environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability. These assumptions involve the judgments and estimates of management and any changes in assumptions could lead to increases or decreases in our ultimate liability, with any such changes recognized immediately in earnings.
We follow the guidance of FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FIN No. 45”), for disclosure and accounting of various guarantees and indemnifications entered into during the course of business. When a guarantee or indemnification subject to FIN No. 45 is entered into, an estimated fair value of the underlying guarantee or indemnification is recorded. Some guarantees and indemnifications could have significant financial impact under certain circumstances, however management also considers the probability of such circumstances occurring when estimating the fair value. Actual results may materially differ from the estimated fair value of such guarantees and indemnifications.
Please read Note 19—Commitments and Contingencies for further discussion of our commitments and contingencies.
Accounting for Asset Retirement Obligations
Under the provisions of SFAS No. 143, “Asset Retirement Obligations” (“SFAS No. 143”), and FIN No. 47 “Accounting for Conditional Asset Retirements” (“FIN No. 47”), we are required to record the present value of the future obligations to retire tangible, long-lived assets on our consolidated balance sheets as liabilities when the liability is incurred. Significant judgment is involved in estimating our future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates for the amount or timing of the cash flows change, the change may have a material impact on our results of operations.
Please read Note 2—Summary of Significant Accounting Policies—Asset Retirement Obligations for further discussion of our accounting for AROs.
Accounting for Variable Interest Entities
We follow the guidance in FIN 46(R), “Consolidation of Variable Interest Entities”, which requires that we evaluate certain entities to determine which party is considered the primary beneficiary of the entity and thus required to consolidate it in its financial statements. We are an investor in several variable interest entities to which LS Power, a related party, is also an investor. There is a significant amount of judgment involved in determining the primary beneficiary of an entity from a related party group. We have concluded that we are not the primary beneficiary of these entities because a) we believe that LS Power is more closely associated with the entities, b) they own approximately 40 percent of Dynegy’s outstanding common stock and c) they have three seats on Dynegy’s Board of Directors. If different judgment was applied, we could be considered the primary beneficiary of some or all of these entities, which would significantly impact our financial condition and results of operations. Please read Note 12—Variable Interest Entities for further discussion of our accounting for our variable interest entities.
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We are also an investor, with independent third parties, in PPEA. PPEA is a variable interest entity, and there is a significant amount of judgment involved in the analysis used to determine the primary beneficiary. The analysis includes assumptions about forecasted cash flows, construction costs, and plant performance. We have concluded that we are the primary beneficiary of Plum Point and therefore consolidate the entity in our consolidated financial statements. If different judgment was applied, we may not be considered the primary beneficiary for this entity, which would significantly impact our financial condition, results of operations and cash flows.
Please read Note 12—Variable Interest Entities for further discussion of our accounting for our variable interest entities.
Accounting for Income Taxes
We follow the guidance in SFAS No. 109, “Accounting for Income Taxes” (“SFAS No. 109”), which requires that we use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.
As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing tax and accounting treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheets.
Because we operate and sell power in many different states, our effective annual state income tax rate will vary from period to period because of changes in our sales profile by state, as well as jurisdictional and legislative changes by state. As a result, changes in our estimated effective annual state income tax rate can have a significant impact on our measurement of temporary differences. A change of 1 percent in the estimated effective annual state income tax rate at December 31, 2007, could impact deferred tax expense by approximately $26 million for Dynegy and $20 million for DHI. State statutory tax rates in the states in which we do business range from 1 percent to 8.84 percent.
We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50 percent) that some portion or all of the deferred tax assets will not be realized, we must establish a valuation allowance. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.
Management believes future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize deferred tax assets for which no reserve has been established. While we have considered these factors in assessing the need for a valuation allowance, there is no assurance that a valuation allowance would not need to be established in the future if information about future years changes. Any change in the valuation allowance would impact our income tax (expense) benefit and net income (loss) in the period in which such a determination is made.
Effective January 1, 2007, we adopted FIN No. 48 which requires that we determine if it is more likely than not that a tax position we have taken will be sustained upon examination. If we determine that it is more likely than not that the position will be sustained, we recognize the largest amount of the benefit that is greater than 50 percent likely of being realized upon settlement. There is a significant amount of judgment involved in assessing the likelihood that a tax position will be sustained upon examination and in determining the amount of the benefit that will ultimately be realized. If different judgment were applied, it could significantly impact our financial condition and results of operations.
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Please read Note 17—Income Taxes for further discussion of our accounting for income taxes, adoption of FIN No. 48 and change in our valuation allowance.
Valuation of Pension and Other Post-Retirement Plans Assets and Liabilities
Our pension and other post-retirement benefit costs are developed from actuarial valuations. Inherent in these valuations are key assumptions including the discount rate and expected long-term rate of return on plan assets. Material changes in our pension and other post-retirement benefit costs may occur in the future due to changes in these assumptions, changes in the number of plan participants and changes in the level of benefits provided.
We used a yield curve approach for determining the discount rate as of December 31, 2007. The discount rate is subject to change each year, consistent with changes in applicable high-quality, long-term corporate bond indices. Projected benefit payments for the plans were matched against the discount rates in the Citigroup Pension Discount Curve to produce a weighted-average equivalent discount rate. Long-term interest rates increased during 2007. Accordingly, at December 31, 2007, we used a discount rate of 6.46 percent for pension plans and 6.48 percent for other retirement plans, an increase of 59 and 58 basis points, respectively, from the 5.87 percent for pension plans rate and 5.90 percent for other retirement plans rate used as of December 31, 2006. This increase in the discount rate decreased the underfunded status of the plans by $20 million.
The expected long-term rate of return on pension plan assets is selected by taking into account the asset mix of the plans and the expected returns for each asset category. Based on these factors, our expected long-term rate of return as of January 1, 2008 and 2007 was 8.25 percent.
A relatively small difference between actual results and assumptions used by management may have a material effect on our financial statements. Assumptions used by another party could be different than our assumptions. The following table summarizes the sensitivity of pension expense and our projected benefit obligation, or PBO, to changes in the discount rate and the expected long-term rate of return on pension assets:
| Impact on PBO, December 31, 2007 |
Impact on 2008 Expense |
|||||||
| (in millions) | ||||||||
| Increase in Discount Rate—50 basis points |
$ | (16 | ) | $ | (1 | ) | ||
| Decrease in Discount Rate—50 basis points |
17 | 2 | ||||||
| Increase in Expected Long-term Rate of Return—50 basis points |
— | (1 | ) | |||||
| Decrease in Expected Long-term Rate of Return—50 basis points |
— | 1 | ||||||
We expect to make $29 million in cash contributions related to our pension plans during 2008. In addition, we may be required to continue to make contributions to the pension plans beyond 2008. Although it is difficult to estimate these potential future cash requirements due to uncertain market conditions, we currently expect that we will contribute approximately $9 million in 2009 and $11 million in 2010.
Please read Note 21—Employee Compensation, Savings and Pension Plans for further discussion of our pension-related assets and liabilities.
RECENT ACCOUNTING PRONOUNCEMENTS
Please read Note 2—Summary of Significant Accounting Policies—Accounting Policies Not Yet Adopted for further discussion for accounting policies not yet adopted. We adopted FIN No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN No. 48”) on January 1, 2007. We adopted SFAS No. 123(R) and SFAS No. 154, “Accounting Changes and Error Corrections—A Replacement of APB Opinion No. 20 and SFAS No. 3”, on January 1, 2006 and SFAS No. 158 on December 31, 2006. We adopted EITF Issue 05-6, “Determining the Amortization Period for Leasehold Improvements”, and FSP FIN No. 45-3, “Application of FASB Interpretation No. 45 to Minimum Revenue Guarantees Granted to a Business or Its Owners”, on January 1, 2006. We adopted FIN No. 47 on December 31, 2005.
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RISK-MANAGEMENT DISCLOSURES
The following table provides a reconciliation of the risk-management data on the consolidated balance sheets:
| As of and for the Year Ended December 31, 2007 |
||||
| (in millions) | ||||
| Balance Sheet Risk-Management Accounts |
||||
| Fair value of portfolio at January 1, 2007 |
$ | 53 | ||
| Risk-management gains recognized through the income statement in the period, net |
97 | |||
| Cash received related to risk-management contracts settled in the period, net |
(82 | ) | ||
| Changes in fair value as a result of a change in valuation technique (1) |
— | |||
| Non-cash adjustments and other (2) |
(168 | ) | ||
| Fair value of portfolio at December 31, 2007 |
$ | (100 | ) | |
| (1) | Our modeling methodology has been consistently applied. |
| (2) | This amount consists of $38 million in net risk management liabilities acquired in connection with the Merger Agreement as well as changes in value associated with cash flow hedges on forward power sales and interest payments on our Plum Point project debt and fair value hedges on debt. |
The net risk-management liability of $100 million is the aggregate of the following line items on the consolidated balance sheets: Current Assets—Assets from risk-management activities, Other Assets—Assets from risk-management activities, Current Liabilities—Liabilities from risk-management activities and Other Liabilities—Liabilities from risk-management activities.
Risk-Management Asset and Liability Disclosures
The following table depicts the mark-to-market value and cash flow components, based on contract terms, of our net risk-management assets and liabilities at December 31, 2007. As opportunities arise to monetize positions that we believe will result in an economic benefit to us, we may receive or pay cash in periods other than those depicted below.
Net Risk-Management Asset and Liability Disclosures
| Total |
2008 |
2009 |
2010 |
2011 |
2012 |
Thereafter | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||
| Mark-to-Market (1) |
$ | (100 | ) | $ | (30 | ) | $ | (63 | ) | $ | (12 | ) | $ | 1 | $ | 1 | $ | 3 | |||||||
| Cash Flow (2) |
(100 | ) | (28 | ) | (68 | ) | (12 | ) | 2 | 1 | 5 | ||||||||||||||
| (1) | Mark-to-market reflects the fair value of our net risk-management position, which considers time value, credit, price and other reserves necessary to determine fair value. Cash flows have been segregated between periods based on the delivery date required in the individual contracts. |
| (2) | Cash flow reflects undiscounted cash inflows and outflows by contract based on the tenor of individual contract position for the remaining periods. These anticipated undiscounted cash flows have not been adjusted for counterparty credit or other reserves. |
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The following table provides an assessment of net contract values by year as of December 31, 2007, based on our valuation methodology:
Net Fair Value of Risk-Management Portfolio
| Total |
2008 |
2009 |
2010 |
2011 |
2012 |
Thereafter | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||
| Market Quotations (1) |
$ | (75 | ) | $ | (34 | ) | $ | (44 | ) | $ | (2 | ) | $ | 1 | $ | 1 | $ | 3 | |||||||
| Value Based on Models (2) |
(25 | ) | 4 | (19 | ) | (10 | ) | — | — | — | |||||||||||||||
| Total |
$ | (100 | ) | $ | (30 | ) | $ | (63 | ) | $ | (12 | ) | $ | 1 | $ | 1 | $ | 3 | |||||||
| (1) | Price inputs obtained from actively traded, liquid markets for commodities other than natural gas positions. All natural gas positions for all periods are contained in this line based on available market quotations. |
| (2) | Based on internally developed models that include assumptions for future prices of energy based on the specific market in which the energy is being sold, using externally available forward market pricing curves for all periods possible under the pricing model. |
Derivative Contracts
The absolute notional contract amounts associated with our commodity risk-management and interest rate contracts are discussed in Item 7A. Quantitative and Qualitative Disclosures About Market Risk below.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to commodity price variability related to our power generation business and legacy trading portfolio. In addition, fuel requirements at our power generation facilities represent additional commodity price risks to us. In order to manage these commodity price risks, we routinely utilize various fixed-price forward purchase and sales contracts, futures and option contracts traded on the New York Mercantile Exchange and swaps and options traded in the over-the-counter financial markets to:
| • | manage and hedge our fixed-price purchase and sales commitments; |
| • | reduce our exposure to the volatility of cash market prices; and |
| • | hedge our fuel requirements for our generating facilities. |
The potential for changes in the market value of our commodity, interest rate and currency portfolios is referred to as “market risk”. A description of each market risk category is set forth below:
| • | commodity price risks result from exposures to changes in spot prices, forward prices and volatilities in commodities, such as electricity, natural gas, coal, fuel oil, emissions and other similar products; and |
| • | interest rate risks primarily result from exposures to changes in the level, slope and curvature of the yield curve and the volatility of interest rates. |
In the past, we have attempted to manage these market risks through diversification, controlling position sizes and executing hedging strategies. The ability to manage an exposure may, however, be limited by adverse changes in market liquidity, our credit capacity or other factors.
VaR. In addition to applying business judgment, we use a number of quantitative tools to monitor our exposure to market risk. These tools include stress and scenario analyses performed periodically that measure the potential effects of various market events.
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The modeling of the risk characteristics of our mark-to-market portfolio involves a number of assumptions and approximations. We estimate VaR using a JP Morgan RiskMetrics™ approach assuming a one-day holding period. Inputs for the VaR calculation are prices, positions, instrument valuations and the variance-covariance matrix. VaR does not account for liquidity risk or the potential that adverse market conditions may prevent liquidation of existing market positions in a timely fashion. While management believes that these assumptions and approximations are reasonable, there is no uniform industry methodology for estimating VaR, and different assumptions and/or approximations could produce materially different VaR estimates.
We use historical data to estimate our VaR and, to better reflect current asset and liability volatilities, this historical data is weighted to give greater importance to more recent observations. Given our reliance on historical data, VaR is effective in estimating risk exposures in markets in which there are not sudden fundamental changes or shifts in market conditions. An inherent limitation of VaR is that past changes in market risk factors, even when weighted toward more recent observations, may not produce accurate predictions of future market risk. VaR should be evaluated in light of this and the methodology’s other limitations.
VaR represents the potential loss in value of our mark-to-market portfolio due to adverse market movements over a defined time horizon within a specified confidence level. For the VaR numbers reported below, a one-day time horizon and a 95 percent confidence level were used. This means that there is a one in 20 statistical chance that the daily portfolio value will fall below the expected maximum potential reduction in portfolio value at least as large as the reported VaR. Thus, a change in portfolio value greater than the expected change in portfolio value on a single trading day would be anticipated to occur, on average, about once a month. Gains or losses on a single day can exceed reported VaR by significant amounts. Gains or losses can also accumulate over a longer time horizon such as a number of consecutive trading days.
In addition, we have provided our VaR using a one-day time horizon and a 99 percent confidence level. The purpose of this disclosure is to provide an indication of earnings volatility using a higher confidence level. Under this presentation, there is a one in 100 statistical chance that the daily portfolio value will fall below the expected maximum potential reduction in portfolio value at least as large as the reported VaR. We have also disclosed a two-year comparison of daily VaR in order to provide context for the one-day amounts.
The following table sets forth the aggregate daily VaR and average VaR of the mark-to-market portion of our generation business and legacy trading portfolio primarily associated with the GEN segments and the CRM business. The VaR calculation does not include market risks associated with the accrual portion of the risk-management portfolio that is designated as a cash flow hedge or a “normal purchase normal sale”, nor does it include expected future production from our generating assets. Another limitation to our calculation of VaR is our use of the JP Morgan RiskMetrics TM approach, which calculates option values using a linear approximation. With the acquisition of several financially-settled heat rate call-option agreements in the LS Power business combination, the actual change in the fair value of these instruments may differ significantly from the calculated VaR.
There is a significant increase in VaR from December 31, 2006 to December 31, 2007 due to the above mentioned financially-settled heat rate call-options and our decision to cease designating certain derivative transactions as cash flow hedges, beginning on April 2, 2007.
Daily and Average VaR for Mark-to-Market Portfolios
| December 31, 2007 |
December 31, 2006 | |||||
| (in millions) | ||||||
| One day VaR—95 percent confidence level |
$ | 24 | $ | 1 | ||
| One day VaR—99 percent confidence level |
$ | 35 | $ | 1 | ||
| Average VaR for the year-to-date period—95 percent confidence level |
$ | 20 | $ | 3 | ||
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Credit Risk. Credit risk represents the loss that we would incur if a counterparty fails to perform pursuant to the terms of its contractual obligations. To reduce our credit exposure, we execute agreements that permit us to offset receivables, payables and mark-to-market exposure. We attempt to further reduce credit risk with certain counterparties by obtaining third party guarantees or collateral as well as the right of termination in the event of default.
Our Credit Department, based on guidelines approved by the Board of Directors, establishes our counterparty credit limits. Our industry typically operates under negotiated credit lines for physical delivery and financial contracts. Our credit risk system provides current credit exposure to counterparties on a daily basis.
The following table represents our credit exposure at December 31, 2007 associated with the mark-to-market portion of our risk-management portfolio, on a net basis.
Credit Exposure Summary
| Investment Grade Quality | |||
| (in millions) | |||
| Type of Business: |
|||
| Financial institutions |
$ | 263 | |
| Utility and power generators |
35 | ||
| Total |
$ | 298 | |
Interest Rate Risk. Interest rate risk primarily results from variable rate debt obligations. Although changing interest rates impact the discounted value of future cash flows, and therefore the value of our risk management portfolios, the relative near-term nature and size of our risk management portfolios minimizes the impact. Management continues to monitor our exposure to fluctuations in interest rates and may execute swaps or other financial instruments to change our risk profile for this exposure.
We are exposed to fluctuating interest rates related to variable rate financial obligations. As of December 31, 2007, our fixed rate debt instruments as a percentage of total debt instruments was 78 percent. Adjusted for interest rate swaps, net notional fixed rate debt as a percentage of total debt was approximately 82 percent. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of December 31, 2007, it is estimated that a one percentage point interest rate movement in the average market interest rates (either higher or lower) over the twelve months ended December 31, 2008 would either decrease or increase interest expense by approximately $11 million. However, interest rate risk associated with our $850 million variable rate term letter of credit facility is mitigated by restricted cash backing this facility. Variable rate interest income earned on the investment of the restricted cash effectively offsets the risk associated with the variable rate interest expense. Over time, we may seek to adjust the variable rate exposure in our debt portfolio through the use of swaps or other financial instruments.
Derivative Contracts. The absolute notional financial contract amounts associated with our interest rate contracts were as follows at December 31, 2007 and 2006, respectively:
Absolute Notional Contract Amounts
| December 31, 2007 |
December 31, 2006 | |||||
| Cash flow hedge interest rate swaps (in millions of U.S. dollars) |
$ | 310 | $ | — | ||
| Fixed interest rate paid on swaps (percent) |
5.32 | — | ||||
| Fair value hedge interest rate swaps (in millions of U.S. dollars) |
$ | 25 | $ | 525 | ||
| Fixed interest rate received on swaps (percent) |
5.70 | 4.33 | ||||
| Interest rate risk-management contracts (in millions of U.S. dollars) |
$ | 231 | $ | 306 | ||
| Fixed interest rate paid (percent) |
5.35 | 5.29 | ||||
| Interest rate risk-management contracts (in millions of U.S. dollars) |
$ | 206 | $ | 281 | ||
| Fixed interest rate received (percent) |
5.28 | 5.23 | ||||
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Item 8. Financial Statements and Supplementary Data
Dynegy’s and DHI’s consolidated financial statements and financial statement schedules are set forth at pages F-1 through F-91 inclusive, found at the end of this annual report, and are incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
As previously reported in our Current Report on Form 8-K dated April 16, 2007 (as amended on May 15, 2007), Dynegy’s Audit and Compliance committee appointed Ernst & Young LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2007 and dismissed PricewaterhouseCoopers LLP. During the fiscal years ended December 31, 2007 and 2006, there were no “disagreements with our former accountant” as defined in Item 304(a)(1)(iv) of Regulation S-K. We previously disclosed two material weaknesses as defined in Item 304(a)(1)(v) of Regulation S-K related to (i) a failure to maintain effective controls over the completeness and accuracy of the tax provision and deferred income tax balances in accordance with generally accepted accounting principles as of December 31, 2004 and 2005 and September 30, 2006 and (ii) a failure to maintain effective internal control over its financial reporting due to a material weakness in its processes, procedures and controls related to the calculation and analysis of its risk management asset and liability balances during the nine-month period ended September 30, 2006. Both material weaknesses were remediated as of December 31, 2006. Dynegy Illinois and DHI previously authorized PricewaterhouseCoopers LLP to respond fully to the inquiries of the successor independent registered public accountant concerning the subject matter of each of the two material weaknesses described above. Please read the Current Report on Form 8-K of Dynegy Inc. filed on May 15, 2007 for further information.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of Dynegy’s and DHI’s management, including their Chief Executive Officer and their Chief Financial Officer, of the effectiveness of the design and operation of the consolidated enterprise’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). This evaluation included consideration of the various processes carried out under the direction of Dynegy’s disclosure committee in an effort to ensure that information required to be disclosed in the consolidated enterprise’s SEC reports is recorded, processed, summarized and reported within the time periods specified by the SEC. This evaluation also considered the work completed relating to our compliance with Section 404 of the Sarbanes-Oxley Act of 2002. Based on this evaluation, Dynegy’s and DHI’s CEO and CFO concluded that Dynegy’s and DHI’s disclosure controls and procedures were effective as of December 31, 2007.
Management’s Report on Internal Control over Financial Reporting
Dynegy’s and DHI’s management are responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Dynegy’s and DHI’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Dynegy’s and DHI’s internal control over financial reporting includes those policies and procedures that:
| (i) | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; |
| (ii) | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of our company are being made only in accordance with authorizations of our management and directors; and |
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| (iii) | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements. |
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of both Dynegy’s and DHI’s internal control over financial reporting as of December 31, 2007. In making this assessment, we used the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this assessment and on those criteria, we concluded that both Dynegy’s and DHI’s internal control over financial reporting was effective as of December 31, 2007.
The effectiveness of Dynegy’s internal control over financial reporting as of December 31, 2007 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included herein.
Changes in Internal Controls Over Financial Reporting
There were no changes in the consolidated enterprise’s internal control over financial reporting that have materially affected or are reasonably likely to materially affect the consolidated enterprise’s internal control over financial reporting during the quarter ended December 31, 2007.
Not applicable.
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PART III
Item 10. Directors, Executive Officers and Corporate Governance
Dynegy
Code of Ethics. We have adopted a Code of Ethics within the meaning of Item 406(b) of Regulation S-K. This Code of Ethics applies to our Chief Executive Officer, Chief Financial Officer, Controller and other persons performing similar functions designated by the Chief Financial Officer, and is filed as an exhibit to this Form 10-K.
Other Information. We intend to include the other information required by this Item 10 in Dynegy’s definitive proxy statement for its 2008 annual meeting of stockholders under the headings “Proposal 1—Election of Directors” and “Compliance with Section 16(a) of the Exchange Act,” which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2007.
DHI
Omitted pursuant to General Instruction (1)(2)(c) of Form 10-K.
Item 11. Executive Compensation
Dynegy. We intend to include information with respect to executive compensation in Dynegy’s definitive proxy statement for its 2008 annual meeting of stockholders under the heading “Executive Compensation”, which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2007.
DHI. Omitted pursuant to General Instruction (1)(2)(c) of Form 10-K.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Dynegy. The following table sets forth certain information as of December 31, 2007 as it relates to Dynegy’s equity compensation plans for its Class A common stock, the only class with respect to which Dynegy offers equity compensation.
Securities Authorized for Issuance Under Equity Compensation Plans
| Plan Category |
Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) |
Weighted-average exercise price of outstanding options, warrants and rights (b) |
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) | ||||
| Equity compensation plans approved by security holders |
5,982,159 | $ | 12.57 | 12,188,221 | |||
| Equity compensation plans not approved by security holders (1) |
2,438,201 | $ | 12.68 | 3,571,111 | |||
| Total |
8,420,360 | $ | 12.60 | 15,759,332 | |||
| (1) | The plans that were not approved by Dynegy’s security holders are as follows: Extant Inc. 401(K) Plan, Dynegy 2001 Non-Executive Stock Incentive Plan and Dynegy UK Plan. Please read Note 20—Capital Stock—Stock Award Plans for a brief description of Dynegy’s equity compensation plans, including these plans. |
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We intend to include information regarding ownership of Dynegy’s outstanding securities in Dynegy’s definitive proxy statement for its 2008 annual meeting of stockholders under the heading “Security Ownership of Certain Beneficial Owners and Management”, which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2007.
DHI. Omitted pursuant to General Instruction (1)(2)(c) of Form 10-K.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Dynegy. We intend to include the information regarding related party transactions in Dynegy’s definitive proxy statement for its 2008 annual meeting of stockholders under the headings “Corporate Governance” and “Transactions with Related Persons, Promoters and Certain Control Persons”, which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2007.
DHI. Omitted pursuant to General Instruction (1)(2)(c) of Form 10-K.
Item 14. Principal Accountant Fees and Services
Dynegy. We intend to include information regarding principal accountant fees and services in Dynegy’s definitive proxy statement for its 2008 annual meeting of stockholders under the heading “Independent Auditors”, which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2007.
DHI. DHI is an indirect, wholly owned subsidiary of Dynegy and does not have a separate audit committee. Information regarding principal accountant fees and services for Dynegy and its consolidated subsidiaries, including DHI, will be contained in Dynegy’s definitive proxy statement for its 2008 annual meeting of stockholders under the heading “Independent Auditors—Principal Accounting Fees and Services”. Such proxy statement will be filed with the SEC not later than 120 days after December 31, 2007.
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PART IV
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents, which we have filed with the SEC pursuant to the Securities Exchange Act of 1934, as amended, are by this reference incorporated in and made a part of this report:
1. Financial Statements—Our consolidated financial statements are incorporated under Item 8. of this report.
2. Financial Statement Schedules—Financial Statement Schedules are incorporated under Item 8. of this report.
3. Exhibits—The following instruments and documents are included as exhibits to this report. All management contracts or compensation plans or arrangements set forth in such list are marked with a ††.
All other schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.
| Exhibit Number |
Description | |
| 2.1 | —Plan of Merger, Contribution and Sale Agreement, dated September 14, 2006 by and among Dynegy Inc., LSP Gen Investors, LP, LS Power Partners, LP, LS Power Equity Partners PIE I, L.P., LS Power Equity Partners, L.P., LS Power Associates, L.P., Falcon Merger Sub Co. and Dynegy Acquisition, Inc. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659). | |
| 2.2 | —Limited Liability Company Membership Interests and Stock Purchase Agreement, dated as of September 14, 2006, among LS Power Associates, L.P., LS Power Equity Partners, L.P., LS Power Equity Partners PIE I, L.P., LS Power Partners, L.P. and Kendall Power LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659). | |
| 3.1 | —Amended and Restated Certificate of Incorporation of Dynegy Inc. (formerly named Dynegy Acquisitions, Inc.) (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-141810). | |
| 3.2 | —Amended and Restated Bylaws of Dynegy Inc. (formerly named Dynegy Acquisitions, Inc.) (incorporated by reference to Exhibit 4.2 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-141810). | |
| 3.3 | —Restated Certificate of Incorporation of Dynegy Holdings Inc. (incorporated by reference to Exhibit 3.1 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Holdings Inc., File No. 000-29311). | |
| 3.4 | —Amended and Restated Bylaws of Dynegy Holdings, Inc. (incorporated by reference to Exhibit 3.2 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Holdings Inc., File No. 000-29311). | |
| 4.1 | —Subordinated Debenture Indenture between NGC Corporation and The First National Bank of Chicago, as Debenture Trustee, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156). | |
| 4.2 | —Amended and Restated Declaration of Trust among NGC Corporation, Wilmington Trust Company, as Property Trustee and Delaware Trustee, and the Administrative Trustees named therein, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.6 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156). | |
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| Exhibit Number |
Description | |
| 4.3 | —Series A Capital Securities Guarantee Agreement executed by NGC Corporation and The First National Bank of Chicago, as Guarantee Trustee, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.9 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156). | |
| 4.4 | —Common Securities Guarantee Agreement of NGC Corporation, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.10 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156). | |
| 4.5 | —Registration Rights Agreement, dated as of May 28, 1997, among NGC Corporation, NGC Corporation Capital Trust I, Lehman Brothers, Salomon Brothers Inc. and Smith Barney Inc. (incorporated by reference to Exhibit 4.11 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156). | |
| 4.6 | —Indenture, dated as of September 26, 1996, restated as of March 23, 1998, and amended and restated as of March 14, 2001, between Dynegy Holdings Inc. and Bank One Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.17 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2000 of Dynegy Holdings Inc., File No. 000-29311). | |
| 4.7 | —First Supplemental Indenture, dated July 25, 2003 to that certain Indenture, dated as of September 26, 1996, between Dynegy Holdings Inc. and Wilmington Trust Company, as trustee (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on July 28, 2003, File No. 1-15659). | |
| 4.8 | —Second Supplemental Indenture, dated as of April 12, 2006, to that certain Indenture, originally dated as of September 26, 1996, as amended and restated as of March 23, 1998 and again as of March 14, 2001, by and between Dynegy Holdings Inc. and Wilmington Trust Company (as successor to JPMorgan Chase Bank, N.A.), as trustee, as supplemented by that certain First Supplemental Indenture, dated as of July 25, 2003 (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on April 12, 2006, File No. 1-15659). | |
| 4.9 | —Third Supplemental Indenture, dated as of May 24, 2007, to that certain Indenture, originally dated as of September 26, 1996, as amended and restated as of March 23, 1998 and again as of March 14, 2001, by and between Dynegy Holdings Inc. and Wilmington Trust Company (as successor to JPMorgan Chase Bank, N.A.), as trustee, as supplemented by that certain First Supplemental Indenture, dated as of July 25, 2003, and that certain Second Supplemental Indenture, dated as of April 12, 2006 (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on May 25, 2007, File No. 000-29311). | |
| 4.10 | —Fourth Supplemental Indenture, dated as of May 24, 2007, to that certain Indenture, originally dated as of September 26, 1996, as amended and restated as of March 23, 1998 and again as of March 14, 2001, by and between Dynegy Holdings Inc. and Wilmington Trust Company (as successor to JPMorgan Chase Bank, N.A.), as trustee, as supplemented by that certain First Supplemental Indenture, dated as of July 25, 2003, that certain Second Supplemental Indenture, dated as of April 12, 2006, and that certain Third Supplemental Indenture, dated as of May 24, 2007 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on May 25, 2007, File No. 000-29311). | |
| 4.11 | —Registration Rights Agreement, effective as of July 21, 2006, by and among Dynegy Holdings Inc. RCP Debt, LLC and RCMF Debt, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on July 24, 2006, File No. 1-15659). | |
| 4.12 | —Registration Rights Agreement, dated as of May 24, 2007, by and among Dynegy Holdings Inc. and the several initial purchasers party thereto (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on May 25, 2007, File No. 000-29311). | |
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| Exhibit Number |
Description | |
| 4.13 | —Trust Indenture, dated as of January 1, 1993, among Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P. and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.22 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659). | |
| 4.14 | —First Supplemental Indenture, dated as of January 1, 1993, to the Trust Indenture dated as of January 1, 1993, among Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P. and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.23 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659). | |
| 4.15 | —Second Supplemental Indenture, dated as of October 23, 2001, to the Trust Indenture dated as of January 1, 1993, among Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P. and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.24 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659). | |
| 4.16 | —Global Note representing the 9.00 percent Secured Bonds due 2013 of Sithe/Independence Power Partners, L.P. (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2005 of Dynegy Inc., File No. 1-15659). | |
| 4.17 | —Shareholder Agreement, dated as of September 14, 2006, among Dynegy Acquisition, Inc. and LS Power Partners, L.P., LS Power Associates, L.P., LS Power Equity Partners, L.P., LS Power Equity Partners PIE I, L.P. and LSP Gen Investors, L.P. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659). | |
| 4.18 | —Registration Rights Agreement, dated as of September 14, 2006, among Dynegy Acquisition, Inc., LS Power Partners, L.P., LS Power Associates, L.P., LS Power Equity Partners, L.P., LS Power Equity Partners PIE I, L.P. and LSP Gen Investors, L.P. (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659). | |
| 4.19 | —Lock-Up Agreement, dated as of September 14, 2006, by and among LSP Gen Investors, LP, LS Power Partners, LP, LS Power Associates, L.P., LS Power Equity Partners PIE I, LP, LS Power Equity Partners, L.P. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.5 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659). | |
| 10.1 | —Employment Agreement, dated October 18, 2002, between Bruce A. Williamson and Dynegy Inc. (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2002 of Dynegy Inc., File No. 1-15659). †† | |
| 10.2 | —Second Amendment to October 18, 2002 Employment Agreement, dated September 15, 2005, between Bruce A. Williamson and Dynegy Inc. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659). †† | |
| 10.3 | —Third Amendment to October 18, 2002 Employment Agreement, dated as of March 16, 2006, between Dynegy Inc. and Bruce A. Williamson (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on March 17, 2006, File No. 1-15659). †† | |
| 10.4 | —Fourth Amendment to October 18, 2002 Employment Agreement between Bruce A. Williamson and Dynegy Inc. dated August 23, 2007 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 24, 2007, File No. 001-33443). †† | |
| 10.5 | —Agreement Concerning Employment Agreement and Stock Options, dated as of March 16, 2006, between Dynegy Inc. and Bruce A. Williamson (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 17, 2006, File No. 1-15659). †† | |
93
| Exhibit Number |
Description | |
| 10.6 | —Termination of October 18, 2002 Employment Agreement, dated November 28, 2007, between Bruce A. Williamson and Dynegy Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on November 29, 2007, File No. 1-33443). †† | |
| 10.7 | —Purchase Agreement, dated August 1, 2003, among Dynegy Inc., Dynegy Holdings Inc. and the initial purchasers named therein (incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659). | |
| 10.8 | —Purchase Agreement, dated August 1, 2003, among Dynegy Holdings Inc., the guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659). | |
| 10.9 | —Purchase Agreement, dated September 30, 2003, among Dynegy Holdings Inc., the guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on October 15, 2003, File No. 1-15659). | |
| 10.10 | —Purchase Agreement, dated as of March 29, 2006, for the sale of $750,000,000 aggregate principal amount of the 8.375 percent Senior Unsecured Notes due 2016 of Dynegy Holdings Inc. among Dynegy Holdings Inc. and the several initial purchasers named therein (incorporated by reference to Exhibit 10.11 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2006 of Dynegy Inc., File No. 1-15659). | |
| 10.11 | —Purchase Agreement, dated as of May 17, 2007, by and between Dynegy Holdings Inc. and J.P. Morgan Securities Inc. (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for Quarterly Period Ended June 30, 2007 of Dynegy Holdings Inc., File No. 000-29311). | |
| 10.12 | —Stock Purchase Agreement, dated as of November 1, 2004, among Dynegy New York Holdings Inc., Exelon SHC, Inc., Exelon New England Power Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.48 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc. File No. 1-15659). | |
| 10.13 | —Amendment to Stock Purchase Agreement (Special Payroll Payment), dated as of January 28, 2005, among Dynegy New York Holdings Inc., Exelon SHC, Inc., Exelon New England Power Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc. File No. 1-15659). | |
| 10.14 | —Amendment to Stock Purchase Agreement, dated as of January 31, 2005, among Dynegy New York Holdings Inc., Exelon SHC, Inc., Exelon New England Power Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659). | |
| 10.15 | —Amendment to Stock Purchase Agreement (Luz Sale), dated as of January 31, 2005, among Dynegy New York Holdings Inc., Exelon SHC, Inc., Exelon New England Power Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659). | |
| 10.16 | —Purchase Agreement, dated as of May 21, 2006, by and between Dynegy Inc. and Rockingham Power, L.L.C., as sellers, and Duke Power Company LLC d/b/a Duke Energy Carolinas, LLC, as purchaser (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 25, 2006, File No. 1-15659). | |
| 10.17 | —Exchange Agreement, dated as of July 21, 2006, by and among Dynegy Holdings Inc., RCP Debt, LLC and RCMF Debt, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on July 24, 2006, File No. 1-15659). | |
94
| Exhibit Number |
Description | |
| 10.18 | —Corporate Opportunity Agreement, dated as of September 14, 2006, between Dynegy Acquisition, Inc. and LS Power Development, LLC (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659). | |
| 10.19 | —Asset Purchase Agreement, dated January 31, 2007, by and between Dynegy Holdings Inc., Calcasieu Power, LLC and Entergy Gulf States, Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on February 2, 2007, File No. 1-15659). | |
| 10.20 | —Purchase and Sale Agreement dated May 28, 2007 by and between Dynegy Holdings Inc. and EnergyCo, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on May 31, 2007, File No. 000-29311). | |
| 10.21 | —Fifth Amended and Restated Credit Agreement, dated as of April 2, 2007, by and among Dynegy Holdings Inc., as borrower, Dynegy Inc. (formerly named Dynegy Acquisition, Inc.) and Dynegy Inc., as parent guarantors, the other guarantors party thereto, the lenders party thereto and various other parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.22 | —Amendment No. 1, dated as of May 24, 2007, to the Fifth Amended and Restated Credit Agreement, dated as of April 2, 2007, by and among Dynegy Holdings Inc., as borrower, Dynegy Inc. and Dynegy Illinois Inc., as parent guarantors, the other guarantors party thereto, the lenders party thereto and various other parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on May 25, 2007, File No. 000-29311). | |
| 10.23 | —Second Amended and Restated Security Agreement, dated April 2, 2007, by and among Dynegy Holdings Inc., as Borrower, the initial grantors party thereto, Wilmington Trust Company, as corporate trustee, and John M. Beeson, Jr., as individual trustee (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.24 | —Credit Agreement, dated as of March 29, 2007, by and among Plum Point Energy Associates, LLC, as borrower, and the lenders and other parties thereto (incorporated by reference to Exhibit 10.10 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.25 | —Collateral Agency and Intercreditor Agreement, dated as of March 29, 2007, by and among Plum Point Energy Associates, LLC, as borrower, PPEA Holding Company, LLC, as Pledgor, The Bank of New York, as collateral agent, The Royal Bank of Scotland, as Administrative Agent, AMBAC Assurance Corporation, as Loan Insurer, and the other parties thereto (incorporated by reference to Exhibit 10.11 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.26 | —Loan Agreement, dated as of April 1, 2006, by and between the City of Osceola, Arkansas and Plum Point Energy Associates, LLC (incorporated by reference to Exhibit 10.12 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.27 | —Trust Indenture, dated as of April 1, 2006, by and between the City of Osceola, Arkansas and Regions Bank, as trustee (incorporated by reference to Exhibit 10.13 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| **10.28 | —First Supplemental Trust Indenture dated as of April 24, 2007, by and between the City of Osceola, Arkansas and Regions Bank, as trustee. | |
| 10.29 | —Limited Liability Company Agreement of DLS Power Development Company, LLC, dated April 2, 2007, by and between LS Power Associates, L.P. and Dynegy Inc. (formerly named Dynegy Acquisition, Inc.) (incorporated by reference to Exhibit 10.15 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.30 | —Amended and Restated Limited Liability Company Agreement of DLS Power Holdings, LLC, dated April 2, 2007, by and between LS Power Associates, L.P. and Dynegy Inc. (formerly named Dynegy Acquisition, Inc.) (incorporated by reference to Exhibit 10.14 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
95
| Exhibit Number |
Description | |
| **10.31 | —Dynegy Inc. Executive Severance Pay Plan, as amended and restated effective as of January 30, 2008. †† | |
| 10.32 | — Second Supplement to the Dynegy Inc. Executive Severance Pay Plan, dated November 20, 2003 (incorporated by reference to Exhibit 99.4 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659). †† | |
| 10.33 | —First Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan, dated June 22, 2005 (incorporated by reference to Exhibit 99.5 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659). †† | |
| 10.34 | —Second Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan, dated September 15, 2005 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659). †† | |
| 10.35 | —Third Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan, dated October 31, 2005 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659). †† | |
| 10.36 | —Fourth Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan, dated as of March 30, 2007 (incorporated by reference to Exhibit 10.16 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| **10.37 | —Dynegy Inc. Severance Pay Plan, as amended and restated effective as of January 30, 2008. †† | |
| 10.38 | —First Supplemental Plan to the Dynegy Inc. Severance Pay Plan, dated June 22, 2005 (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659). †† | |
| 10.39 | —First Amendment to the First Supplemental Plan to the Dynegy Inc. Severance Pay Plan, dated October 31, 2005 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659). †† | |
| 10.40 | —Second Amendment to the First Supplemental Plan to the Dynegy Inc. Severance Pay Plan, dated as of March 30, 2007 (incorporated by reference to Exhibit 10.18 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.41 | —Dynegy Inc. Excise Tax Reimbursement Policy (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on January 4, 2008, File No. 001-33443). †† | |
| 10.42 | —Dynegy Northeast Generation, Inc. Savings Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-111985). †† | |
| 10.43 | —Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan, effective January 1, 2004 (incorporated by reference to Exhibit 10.31 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659). †† | |
| 10.44 | —Second Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan, dated as of December 5, 2005 (incorporated by reference to Exhibit 10.20 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.45 | —Third Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan, dated as of June 7, 2006 (incorporated by reference to Exhibit 10.21 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
96
| Exhibit Number |
Description | |
| 10.46 | —Fourth Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan, dated as of December 15, 2006 (incorporated by reference to Exhibit 10.22 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.47 | —Fifth Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.43 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.48 | —Dynegy Inc. 401(k) Savings Plan, as amended and restated effective January 1, 2002 (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 383-76570). †† | |
| 10.49 | —First Amendment to the Dynegy Inc. 401(k) Savings Plan, effective February 11, 2002 (incorporated by reference to Exhibit 10.19 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659). †† | |
| 10.50 | —Second Amendment to the Dynegy Inc. 401(k) Savings Plan, effective January 1, 2002 (incorporated by reference to Exhibit 10.20 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659). †† | |
| 10.51 | —Third Amendment to the Dynegy Inc. 401(k) Savings Plan, effective October 1, 2003 (incorporated by reference to Exhibit 10.21 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659). †† | |
| 10.52 | —Amendment to the Dynegy Inc. 401(k) Savings Plan, effective January 1, 2004 (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659). †† | |
| 10.53 | —Fifth Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of January 28, 2005 (incorporated by reference to Exhibit 10.23 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.54 | —Sixth Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of February 28, 2005 (incorporated by reference to Exhibit 10.24 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.55 | —Seventh Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of May 31, 2005 (incorporated by reference to Exhibit 10.25 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.56 | —Eighth Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of December 18, 2006 (incorporated by reference to Exhibit 10.26 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.57 | —Ninth Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of June 7, 2006 (incorporated by reference to Exhibit 10.27 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.58 | —Ninth Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of December 21, 2006 (incorporated by reference to Exhibit 10.28 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.59 | —Eleventh Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.30 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
97
| Exhibit Number |
Description | |
| 10.60 | —Illinois Power Company Incentive Savings Plan, as amended and restated effective January 1, 2002 (incorporated by reference to Exhibit 10.3 to the Registration Statement on Form S-8 of Dynegy Inc. filed on January 11, 2002, File No. 333-76570). | |
| 10.61 | —First Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan), dated as of October 17, 2003 (incorporated by reference to Exhibit 4.24 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221). | |
| 10.62 | —Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan), dated as of December 23, 2003 (incorporated by reference to Exhibit 4.25 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221). | |
| 10.63 | —Second Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan), dated as of March 31, 2004 (incorporated by reference to Exhibit 4.26 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221). | |
| 10.64 | —Fourth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan), dated as of September 29, 2004 (incorporated by reference to Exhibit 4.27 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221). | |
| 10.65 | —Fifth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan), dated as of May 31, 2005 (incorporated by reference to Exhibit 4.28 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221). | |
| 10.66 | —Sixth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan), dated as of June 7, 2006 (incorporated by reference to Exhibit 4.29 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221). | |
| 10.67 | —Seventh Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan), dated as of December 15, 2006 (incorporated by reference to Exhibit 4.30 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221). | |
| 10.68 | —Eighth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.40 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.69 | —First Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered under a Collective Bargaining Agreement), dated as of October 17, 2003 (incorporated by reference to Exhibit 4.33 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221). | |
| 10.70 | —Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered under a Collective Bargaining Agreement), dated as of December 23, 2003 (incorporated by reference to Exhibit 4.34 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221). | |
98
| Exhibit Number |
Description | |
| 10.71 | —Second Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered under a Collective Bargaining Agreement), dated as of March 31, 2004 (incorporated by reference to Exhibit 4.35 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221). | |
| 10.72 | —Fourth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered under a Collective Bargaining Agreement), dated as of September 29, 2004 (incorporated by reference to Exhibit 4.36 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221). | |
| 10.73 | —Fifth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered under a Collective Bargaining Agreement), dated as of May 31, 2005 (incorporated by reference to Exhibit 4.37 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221). | |
| 10.74 | —Sixth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered under a Collective Bargaining Agreement), dated as of June 7, 2006 (incorporated by reference to Exhibit 4.38 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221). | |
| 10.75 | —Seventh Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered under a Collective Bargaining Agreement), dated as of December 15, 2006 (incorporated by reference to Exhibit 4.39 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221). | |
| 10.76 | —Eighth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered Under a Collective Bargaining Agreement, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.41 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.77 | —Eighth Amendment to the Extant, Inc. 401(k) Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.44 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.78 | —Form of Non-Qualified Stock Option Award Agreement between Dynegy Inc., all of its affiliates and Bruce A. Williamson (incorporated by reference to Exhibit 10.70 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2007 of Dynegy Inc., File No. 1-33443). †† | |
| 10.79 | —Form of Non-Qualified Stock Option Award Agreement (incorporated by reference to Exhibit 10.73 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2007 of Dynegy Inc., File No. 1-33443). †† | |
| 10.80 | —Form of Restricted Stock Award Agreement between Dynegy Inc., all of its affiliates and Bruce A. Williamson (incorporated by reference to Exhibit 10.71 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2007 of Dynegy Inc., File No. 1-33443). †† | |
| 10.81 | —Form of Restricted Stock Award Agreement (Managing Directors and Above) (incorporated by reference to Exhibit 10.74 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2007 of Dynegy Inc., File No. 1-33443). †† | |
99
| Exhibit Number |
Description | |
| 10.82 | —Form of Restricted Stock Award Agreement (Directors and Below) (incorporated by reference to Exhibit 10.75 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2007 of Dynegy Inc., File No. 1-33443). †† | |
| 10.83 | —Form of Performance Award Agreement between Dynegy Inc., all of its affiliates and Bruce A. Williamson (incorporated by reference to Exhibit 10.72 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2007 of Dynegy Inc., File No. 1-33443). †† | |
| 10.84 | —Form of Performance Award Agreement (incorporated by reference to Exhibit 10.76 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2007 of Dynegy Inc., File No. 1-33443). †† | |
| 10.85 | —Dynegy Inc. Short-Term Executive Stock Purchase Loan Program (incorporated by reference to Exhibit 10.19 to the Annual Report on Form 10-K for the Year Ended December 31, 2001 of Dynegy Inc., File No. 1-15659). †† | |
| 10.86 | —Dynegy Inc. Deferred Compensation Plan (incorporated by reference to Exhibit 4.6 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76080). †† | |
| 10.87 | —Amendment to the Dynegy Inc. Deferred Compensation Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.38 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.88 | —Dynegy Inc. Deferred Compensation Plan for Certain Directors (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659). †† | |
| 10.89 | —First Amendment to the Dynegy Inc. Deferred Compensation Plan for Certain Directors, dated September 15, 2005 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659). †† | |
| 10.90 | —Second Amendment to the Dynegy Inc. Deferred Compensation Plan for Certain Directors dated December 16, 2005 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on December 22, 2005, File No. 1-15659). †† | |
| 10.91 | —Third Amendment to the Dynegy Inc. Deferred Compensation Plan for Certain Directors, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.37 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.92 | —Dynegy Inc. Incentive Compensation Plan, as amended and restated effective January 1, 2006 (incorporated by reference to Exhibit 10.36 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2005 of Dynegy Inc. File No. 1-15659). †† | |
| 10.93 | —First Amendment to the Dynegy Inc. Incentive Compensation Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.32 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.94 | —Dynegy Inc. Amended and Restated Employee Equity Option Plan (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156). †† | |
| 10.95 | —Dynegy Inc. 1999 Long Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156). †† | |
100
| Exhibit Number |
Description | |
| 10.96 | —First Amendment to the Dynegy Inc. 1999 Long Term Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.33 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.97 | —Dynegy Inc. 2000 Long Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156). †† | |
| 10.98 | —Amendment to the Dynegy Inc. 2000 Long Term Incentive Plan effective January 1, 2006 (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on March 17, 2006, File No. 1-15659). †† | |
| 10.99 | —Second Amendment to the Dynegy Inc. 2000 Long Term Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.34 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.100 | —Dynegy Inc. 2002 Long Term Incentive Plan (incorporated by reference to Appendix A to the Definitive Proxy Statement on Schedule 14A of Dynegy Inc., File No. 1-15659, filed with the SEC on April 9, 2002). †† | |
| 10.101 | —Amendment to the Dynegy Inc. 2002 Long Term Incentive Plan, effective January 1, 2006 (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K of Dynegy Inc. filed on March 17, 2006, File No. 1-15659). †† | |
| 10.102 | —Second Amendment to the Dynegy Inc. 2002 Long Term Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.36 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.103 | —Dynegy Inc. 2001 Non-Executive Stock Incentive Plan (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76080). | |
| 10.104 | —First Amendment to the Dynegy Inc. 2001 Non-Executive Stock Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.35 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.105 | —Ninth Amendment to the Dynegy Inc. Retirement Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.29 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.106 | —Sixth Amendment to the Dynegy Inc. Comprehensive Welfare Benefits Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.31 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.107 | —Sixth Amendment to the Dynegy Midwest Generation, Inc. Retirement Income Plan for Employees Covered Under a Collective Bargaining Agreement, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.39 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.108 | —Seventh Amendment to the Dynegy Northeast Generation, Inc. Retirement Income Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.42 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.109 | —Master Trust Agreement, dated as of January 1, 2002 (Vanguard) (incorporated by reference to Exhibit 10.45 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
101
| Exhibit Number |
Description | |
| 10.110 | —Agreement and Amendment to Master Trust Agreement, dated as of December 31, 2003 (Vanguard) (incorporated by reference to Exhibit 10.46 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.111 | —Amendment No. 2 to The Master Trust Agreement, dated as of September 29, 2004 (Vanguard) (incorporated by reference to Exhibit 10.47 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.112 | —Amendment to Master Trust Agreement, dated as of January 1, 2006 (Vanguard) (incorporated by reference to Exhibit 10.48 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.113 | —Amendment to Trust Agreement—DMG 401(k) Savings Plan (Vanguard), dated as of September 29, 2004 (incorporated by reference to Exhibit 10.49 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.114 | —Amendment to Trust Agreement—DMG 401(k) Savings Plan (Vanguard), dated as of January 1, 2006 (incorporated by reference to Exhibit 10.50 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.115 | —Amendment to Trust Agreement—DMG 401(k) Savings Plan (Vanguard), dated as of April 2, 2007 (incorporated by reference to Exhibit 10.51 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.116 | —Dynegy Inc. 401(k) Savings Plan Trust Agreement (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76570). †† | |
| 10.117 | —Amendment to Trust Agreement—Dynegy Inc. 401(k) Savings Plan (Vanguard), dated as of January 1, 2006 (incorporated by reference to Exhibit 10.52 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.118 | —Amendment to Trust Agreement—Dynegy Inc. 401(k) Savings Plan (Vanguard), dated as of April 2, 2007 (incorporated by reference to Exhibit 10.53 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.119 | —Dynegy Inc. Deferred Compensation Plan Trust Agreement (incorporated by reference to Exhibit 4.7 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76080). †† | |
| 10.120 | —Amendment to Dynegy Inc. Deferred Compensation Plan Trust Agreement (Vanguard), dated as of April 2, 2007 (incorporated by reference to Exhibit 10.54 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). †† | |
| 10.121 | —Amendment to Master Trust Agreement (Vanguard Fiduciary Trust Company), dated as of April 2, 2007 (incorporated by reference to Exhibit 10.55 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). | |
| 10.122 | —Asset Purchase Agreement dated January 31, 2007 by and between Dynegy Holdings inc., Calcasieu Power, LLC and Entergy Gulf States, Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on February 2, 2007, File No. 333-139221). | |
| 10.123 | —Purchase Agreement, dated as of May 17, 2007, by and between Dynegy Holdings Inc. and J.P. Morgan Securities Inc. (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for Quarterly Period Ended June 30, 2007 of Dynegy Holdings Inc., File No. 000-29311). | |
| 10.124 | —Equity Commitment Agreement among Sandy Creek Energy Associates, L.P., Dynegy Sandy Creek Holdings, LLC and Credit Suisse dated August 29, 2007 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on September 5, 2007, File No. 000-29311). | |
102
| Exhibit Number |
Description | |
| 10.125 | —Equity Commitment Agreement among Sandy Creek Energy Associates, L.P., Sandy Creek Holdings, LLC and Credit Suisse dated August 29, 2007 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on September 5, 2007, File No. 000-29311). | |
| 10.126 | —Baldwin Consent Decree, approved May 27, 2005 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 31, 2005, File No. 1-15659). | |
| 14.1 | —Dynegy Inc. Code of Ethics for Senior Financial Professionals (incorporated by reference to Exhibit 14.1 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1- 15659). | |
| 16.1 | —Letter of PricewaterhouseCoopers LLP, as amended, dated May 15, 2007 (incorporated by reference to Exhibit 16.1A to the Current Report on Form 8-K/A of Dynegy Holdings Inc. filed on May 15, 2007, File No. 001-33443). | |
| **21.1 | —Subsidiaries of the Registrant (Dynegy Inc.). | |
| 21.2 | —Subsidiaries of the Registrant (Dynegy Holdings Inc.)—Omitted pursuant to General Instruction (1)(2)(c) of Form 10-K. | |
| **23.1 | —Consent of Ernst & Young LLP (Dynegy Inc.). | |
| **23.2 | —Consent of PricewaterhouseCoopers LLP (Dynegy Inc.). | |
| **23.3 | —Consent of Ernst & Young LLP (Dynegy Holdings Inc.). | |
| **23.4 | —Consent of PricewaterhouseCoopers LLP (Dynegy Holdings Inc.). | |
| **31.1 | —Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| **31.1(a) | —Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| **31.2 | —Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| **31.2(a) | —Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| **†32.1 | —Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| **†32.1(a) | —Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| **†32.2 | —Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| **†32.2(a) | —Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| ** | Filed herewith |
| † | Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act. |
| †† | Management contract or compensation plan. |
103
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, the thereunto duly authorized.
| DYNEGY INC. | ||||||
| Date: February 28, 2008 |
By: | /S/ BRUCE A. WILLIAMSON | ||||
| Bruce A. Williamson Chairman of the Board, President and Chief Executive Officer | ||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.
| /S/ BRUCE A. WILLIAMSON Bruce A. Williamson |
Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer) |
February 28, 2008 | ||
| /S/ HOLLI C. NICHOLS Holli C. Nichols |
Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
February 28, 2008 | ||
| /S/ CAROLYN J. STONE Carolyn J. Stone |
Senior Vice President and Controller (Principal Accounting Officer) |
February 28, 2008 | ||
| /S/ JAMES T. BARTLETT James T. Bartlett |
Director |
February 28, 2008 | ||
| /S/ DAVID W. BIEGLER David W. Biegler |
Director |
February 28, 2008 | ||
| /S/ THOMAS D. CLARK, JR. Thomas D. Clark, Jr. |
Director |
February 28, 2008 | ||
| /S/ VICTOR E. GRIJALVA Victor E. Grijalva |
Director |
February 28, 2008 | ||
| /S/ PATRICIA A. HAMMICK Patricia A. Hammick |
Director |
February 28, 2008 | ||
| /S/ FRANK E. HARDENBERGH Frank E. Hardenbergh |
Director |
February 28, 2008 | ||
| /S/ GEORGE L. MAZANEC George L. Mazanec |
Director |
February 28, 2008 | ||
| /S/ MIKHAIL SEGAL Mikhail Segal |
Director |
February 28, 2008 | ||
| /S/ HOWARD B. SHEPPARD Howard B. Sheppard |
Director |
February 28, 2008 | ||
| /S/ WILLIAM L. TRUBECK William L. Trubeck |
Director |
February 28, 2008 | ||
104
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, the thereunto duly authorized.
| DYNEGY HOLDINGS INC. | ||||||
| Date: February 28, 2008 |
By: | /S/ BRUCE A. WILLIAMSON | ||||
| Bruce A. Williamson Chief Executive Officer | ||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.
| /S/ BRUCE A. WILLIAMSON Bruce A. Williamson |
Chief Executive Officer (Principal Executive Officer) |
February 28, 2008 | ||
| /S/ HOLLI C. NICHOLS Holli C. Nichols |
Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer) |
February 28, 2008 | ||
| /S/ CAROLYN J. STONE Carolyn J. Stone |
Senior Vice President and Controller (Principal Accounting Officer) |
February 28, 2008 | ||
| /S/ J. KEVIN BLODGETT J. Kevin Blodgett |
Director |
February 28, 2008 | ||
| /S/ LYNN A. LEDNICKY Lynn A. Lednicky |
Director |
February 28, 2008 | ||
105
DYNEGY INC. AND DYNGEGY HOLDINGS INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| Page | ||
| Consolidated Financial Statements |
||
| Reports of Independent Registered Public Accounting Firms—Dynegy Inc. |
F-2 | |
| Reports of Independent Registered Public Accounting Firms—Dynegy Holdings Inc. |
F-5 | |
| December 31, 2007 and 2006 |
F-7 | |
| For the years ended December 31, 2007, 2006 and 2005 |
F-8 | |
| For the years ended December 31, 2007, 2006 and 2005 |
F-9 | |
| Consolidated Statements of Changes in Stockholders’ Equity—Dynegy Inc.: |
||
| For the years ended December 31, 2007, 2006 and 2005 |
F-10 | |
| Consolidated Statements of Comprehensive Income (Loss)—Dynegy Inc.: |
||
| For the years ended December 31, 2007, 2006 and 2005 |
F-11 | |
| December 31, 2007 and 2006 |
F-12 | |
| For the years ended December 31, 2007, 2006 and 2005 |
F-13 | |
| For the years ended December 31, 2007, 2006 and 2005 |
F-14 | |
| Consolidated Statements of Changes in Stockholder’s Equity—Dynegy Holdings Inc.: |
||
| For the years ended December 31, 2007, 2006 and 2005 |
F-15 | |
| Consolidated Statements of Comprehensive Income (Loss)—Dynegy Holdings Inc.: |
||
| For the years ended December 31, 2007, 2006 and 2005 |
F-16 | |
| F-17 | ||
| Financial Statement Schedules |
||
| Schedule I – Parent Company Financial Statements—Dynegy Inc. |
F-94 | |
| F-98 | ||
| Schedule II – Valuation and Qualifying Accounts—Dynegy Holdings Inc. |
F-99 | |
F-1
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Dynegy Inc.
We have audited the accompanying consolidated balance sheet of Dynegy Inc. as of December 31, 2007, and the related consolidated statements of operations, stockholders’ equity, comprehensive income (loss) and cash flows for the year then ended. Our audit also included the financial statement schedules listed in the Index at Item 15(a) as of and for the year ended December 31, 2007. These financial statements and schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedules based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Dynegy Inc. at December 31, 2007, and the consolidated results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2007 the Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Dynegy Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2008 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 28, 2008
F-2
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Dynegy Inc.
We have audited Dynegy Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Dynegy Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Dynegy Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2007 consolidated financial statements of Dynegy Inc. and our report dated February 28, 2008 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 28, 2008
F-3
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Dynegy Inc.:
In our opinion, the consolidated balance sheet as of December 31, 2006 and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity and cash flows for each of the two years in the period ended December 31, 2006 present fairly, in all material respects, the financial position of Dynegy Inc. and its subsidiaries (the “Company”) at December 31, 2006, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules as of December 31, 2006 and for each of the two years in the period ended December 31, 2006 present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 19, the Company is the subject of substantial litigation. The Company’s ongoing liquidity, financial position and operating results may be adversely impacted by the nature, timing and amount of the resolution of such litigation. The consolidated financial statements do not include any adjustments, beyond existing accruals applicable under Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies”, that might result from the ultimate resolution of such matters.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 27, 2007, except for the effects of discontinued operations described in Note 4, as to which the date is May 14, 2007 for Calcasieu and February 28, 2008 for CoGen Lyondell
F-4
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholder
Dynegy Holdings Inc.
We have audited the accompanying consolidated balance sheet of Dynegy Holdings Inc. as of December 31, 2007, and the related consolidated statements of operations, cash flows, comprehensive income (loss), and stockholder’s equity for the year then ended. Our audit also included the financial statement schedule listed in the Index at Item 15(a) as of and for the year ended December 31, 2007. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Dynegy Holdings Inc. at December 31, 2007, and the consolidated results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2007 the Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes.
/s/ Ernst & Young LLP
Houston, Texas
February 28, 2008
F-5
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholder of Dynegy Holdings Inc.:
In our opinion, the consolidated balance sheet as of December 31, 2006 and the related consolidated statements of operations, comprehensive income (loss), stockholder’s equity and cash flows for each of the two years in the period ended December 31, 2006 present fairly, in all material respects, the financial position of Dynegy Holdings Inc. and its subsidiaries (the “Company”) at December 31, 2006, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for each of the two years in the period ended December 31, 2006, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 19, the Company is the subject of substantial litigation. The Company’s ongoing liquidity, financial position and operating results may be adversely impacted by the nature, timing and amount of the resolution of such litigation. The consolidated financial statements do not include any adjustments, beyond existing accruals applicable under Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies”, that might result from the ultimate resolution of such matters.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 16, 2007, except for the effects of discontinued operations described in Note 4, as to which the date is May 14, 2007 for Calcasieu and August 16, 2007 for CoGen Lyondell, and except for the effects of the transfer of entities under common control as described in Note 3, as to which the date is August 16, 2007
F-6
DYNEGY INC.
(in millions, except share data)
| December 31, 2007 |
December 31, 2006 |
|||||||
| ASSETS | ||||||||
| Current Assets |
||||||||
| Cash and cash equivalents |
$ | 328 | $ | 371 | ||||
| Restricted cash and investments |
104 | 280 | ||||||
| Accounts receivable, net of allowance for doubtful accounts of $20 and $48, respectively |
426 | 257 | ||||||
| Accounts receivable, affiliates |
1 | 1 | ||||||
| Inventory |
199 | 194 | ||||||
| Assets from risk-management activities |
358 | 701 | ||||||
| Deferred income taxes |
45 | 93 | ||||||
| Prepayments and other current assets |
145 | 92 | ||||||
| Assets held for sale (Note 4) |
57 | — | ||||||
| Total Current Assets |
1,663 | 1,989 | ||||||
| Property, Plant and Equipment |
10,689 | 6,473 | ||||||
| Accumulated depreciation |
(1,672 | ) | (1,522 | ) | ||||
| Property, Plant and Equipment, Net |
9,017 | 4,951 | ||||||
| Other Assets |
||||||||
| Unconsolidated investments |
79 | — | ||||||
| Restricted cash and investments |
1,221 | 83 | ||||||
| Assets from risk-management activities |
55 | 16 | ||||||
| Goodwill |
438 | — | ||||||
| Intangible assets |
497 | 347 | ||||||
| Deferred income taxes |
6 | 12 | ||||||
| Other long-term assets |
245 | 139 | ||||||
| Total Assets |
$ | 13,221 | $ | 7,537 | ||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
| Current Liabilities |
||||||||
| Accounts payable |
$ | 292 | $ | 172 | ||||
| Accrued interest |
56 | 66 | ||||||
| Accrued liabilities and other current liabilities |
201 | 231 | ||||||
| Liabilities from risk-management activities |
397 | 629 | ||||||
| Notes payable and current portion of long-term debt |
51 | 68 | ||||||
| Liabilities held for sale (Note 4) |
2 | — | ||||||
| Total Current Liabilities |
999 | 1,166 | ||||||
| Long-term debt |
5,739 | 2,990 | ||||||
| Long-term debt to affiliates |
200 | 200 | ||||||
| Long-Term Debt |
5,939 | 3,190 | ||||||
| Other Liabilities |
||||||||
| Liabilities from risk-management activities |
116 | 35 | ||||||
| Deferred income taxes |
1,250 | 469 | ||||||
| Other long-term liabilities |
388 | 410 | ||||||
| Total Liabilities |
8,692 | 5,270 | ||||||
| Minority Interest |
23 | — | ||||||
| Commitments and Contingencies (Note 19) |
||||||||
| Stockholders’ Equity |
||||||||
| Class A Common Stock, $0.01 par value, 2,100,000,000 shares authorized at December 31, 2007; 502,819,794 shares issued and outstanding at December 31, 2007; and no par value, 900,000,000 shares authorized at December 31, 2006; 403,137,339 shares issued and outstanding at December 31, 2006 |
5 | 3,367 | ||||||
| Class B Common Stock, $0.01 par value, 850,000,000 shares authorized at December 31, 2007; 340,000,000 shares issued and outstanding at December 31, 2007; and no par value, 360,000,000 shares authorized at December 31, 2006; 96,891,014 shares issued and outstanding at December 31, 2006 |
3 | 1,006 | ||||||
| Additional paid-in capital |
6,463 | 39 | ||||||
| Subscriptions receivable |
(5 | ) | (8 | ) | ||||
| Accumulated other comprehensive income (loss), net of tax |
(25 | ) | 67 | |||||
| Accumulated deficit |
(1,864 | ) | (2,135 | ) | ||||
| Treasury stock, at cost, 2,449,259 shares at December 31, 2007 and 1,787,004 shares at December 31, 2006, respectively |
(71 | ) | (69 | ) | ||||
| Total Stockholders’ Equity |
4,506 | 2,267 | ||||||
| Total Liabilities and Stockholders’ Equity |
$ | 13,221 | $ | 7,537 | ||||
See the notes to the consolidated financial statements
F-7
DYNEGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| Revenues |
$ | 3,103 | $ | 1,770 | $ | 2,017 | ||||||
| Cost of sales, exclusive of depreciation shown separately below |
(2,013 | ) | (1,136 | ) | (2,126 | ) | ||||||
| Depreciation and amortization expense |
(325 | ) | (217 | ) | (208 | ) | ||||||
| Impairment and other charges |
— | (119 | ) | (46 | ) | |||||||
| Gain (loss) on sale of assets, net |
43 | 3 | (1 | ) | ||||||||
| General and administrative expenses |
(203 | ) | (196 | ) | (468 | ) | ||||||
| Operating income (loss) |
605 | 105 | (832 | ) | ||||||||
| Earnings (losses) from unconsolidated investments |
(3 | ) | (1 | ) | 2 | |||||||
| Interest expense |
(384 | ) | (382 | ) | (389 | ) | ||||||
| Debt conversion costs |
— | (249 | ) | — | ||||||||
| Other income and expense, net |
56 | 54 | 26 | |||||||||
| Minority interest expense |
(7 | ) | — | — | ||||||||
| Income (loss) from continuing operations before income taxes |
267 | (473 | ) | (1,193 | ) | |||||||
| Income tax (expense) benefit |
(151 | ) | 152 | 393 | ||||||||
| Income (loss) from continuing operations |
116 | (321 | ) | (800 | ) | |||||||
| Income (loss) from discontinued operations, net of tax (expense) benefit of $(91), $10 and $(355), respectively (Note 4) |
148 | (13 | ) | 895 | ||||||||
| Income (loss) before cumulative effect of change in accounting principles |
264 | (334 | ) | 95 | ||||||||
| Cumulative effect of change in accounting principles, net of tax benefit (expense) of zero, zero and $2, respectively (Note 2) |
— | 1 | (5 | ) | ||||||||
| Net income (loss) |
264 | (333 | ) | 90 | ||||||||
| Less: preferred stock dividends (Note 16) |
— | 9 | 22 | |||||||||
| Net income (loss) applicable to common stockholders |
$ | 264 | $ | (342 | ) | $ | 68 | |||||
| Earnings (Loss) Per Share (Note 18): |
||||||||||||
| Basic earnings (loss) per share: |
||||||||||||
| Earnings (loss) from continuing operations |
$ | 0.15 | $ | (0.72 | ) | $ | (2.12 | ) | ||||
| Income (loss) from discontinued operations |
0.20 | (0.03 | ) | 2.31 | ||||||||
| Cumulative effect of change in accounting principles |
— | — | (0.01 | ) | ||||||||
| Basic earnings (loss) per share |
$ | 0.35 | $ | (0.75 | ) | $ | 0.18 | |||||
| Diluted earnings (loss) per share: |
||||||||||||
| Earnings (loss) from continuing operations |
$ | 0.15 | $ | (0.72 | ) | $ | (2.12 | ) | ||||
| Income (loss) from discontinued operations |
0.20 | (0.03 | ) | 2.31 | ||||||||
| Cumulative effect of change in accounting principles |
— | — | (0.01 | ) | ||||||||
| Diluted earnings (loss) per share |
$ | 0.35 | $ | (0.75 | ) | $ | 0.18 | |||||
| Basic shares outstanding |
750 | 459 | 387 | |||||||||
| Diluted shares outstanding |
752 | 509 | 513 | |||||||||
See the notes to the consolidated financial statements
F-8
DYNEGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||||||
| Net income (loss) |
$ | 264 | $ | (333 | ) | $ | 90 | |||||
| Adjustments to reconcile income (loss) to net cash flows from operating activities: |
||||||||||||
| Depreciation and amortization |
333 | 265 | 278 | |||||||||
| Impairment and other charges |
— | 155 | 46 | |||||||||
| Losses from unconsolidated investments, net of cash distributions |
3 | 1 | 73 | |||||||||
| Risk-management activities |
(50 | ) | (87 | ) | 46 | |||||||
| Gain on sale of assets, net |
(267 | ) | (5 | ) | (1,096 | ) | ||||||
| Deferred taxes |
215 | (162 | ) | (73 | ) | |||||||
| Cumulative effect of change in accounting principles (Note 2) |
— | (1 | ) | 5 | ||||||||
| Reserve for doubtful accounts |
— | (35 | ) | 1 | ||||||||
| Independence toll settlement charge (Note 14) |
— | — | 169 | |||||||||
| Legal and settlement charges |
26 | (2 | ) | 119 | ||||||||
| Sterlington toll settlement charge (Note 4) |
— | — | 364 | |||||||||
| Sithe Subordinated Debt exchange charge (Note 12) |
— | 36 | — | |||||||||
| Debt conversion costs |
— | 249 | — | |||||||||
| Other |
42 | 71 | 18 | |||||||||
| Changes in working capital, net of acquired businesses: |
||||||||||||
| Accounts receivable |
(114 | ) | 391 | (134 | ) | |||||||
| Inventory |
(13 | ) | 8 | (91 | ) | |||||||
| Prepayments and other assets |
(37 | ) | 126 | 148 | ||||||||
| Accounts payable and accrued liabilities |
(15 | ) | (885 | ) | (2 | ) | ||||||
| Changes in non-current assets |
(57 | ) | 11 | (15 | ) | |||||||
| Changes in non-current liabilities |
11 | 3 | 24 | |||||||||
| Net cash provided by (used in) operating activities |
341 | (194 | ) | (30 | ) | |||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||
| Capital expenditures |
(379 | ) | (155 | ) | (195 | ) | ||||||
| Unconsolidated investments |
3 | — | — | |||||||||
| Proceeds from asset sales, net |
558 | 227 | 2,488 | |||||||||
| Business acquisitions, net of cash acquired |
(128 | ) | (8 | ) | (120 | ) | ||||||
| Proceeds from exchange of unconsolidated investments, net of cash acquired |
— | 165 | — | |||||||||
| (Increase) decrease in restricted cash |
(871 | ) | 121 | (353 | ) | |||||||
| Other investing, net |
— | 8 | 4 | |||||||||
| Net cash provided by (used in) investing activities |
(817 | ) | 358 | 1,824 | ||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||
| Net proceeds from long-term borrowings |
2,758 | 1,071 | 600 | |||||||||
| Repayments of borrowings |
(2,320 | ) | (1,930 | ) | (1,432 | ) | ||||||
| Debt conversion costs |
— | (249 | ) | — | ||||||||
| Redemption of Series C Preferred (Note 16) |
— | (400 | ) | — | ||||||||
| Net proceeds from issuance of capital stock |
4 | 183 | 2 | |||||||||
| Dividends and other distributions, net |
— | (17 | ) | (22 | ) | |||||||
| Other financing, net |
(9 | ) | — | (21 | ) | |||||||
| Net cash provided by (used in) financing activities |
433 | (1,342 | ) | (873 | ) | |||||||
| Net increase (decrease) in cash and cash equivalents |
(43 | ) | (1,178 | ) | 921 | |||||||
| Cash and cash equivalents, beginning of period |
371 | 1,549 | 628 | |||||||||
| Cash and cash equivalents, end of period |
$ | 328 | $ | 371 | $ | 1,549 | ||||||
See the notes to the consolidated financial statements
F-9
DYNEGY INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(in millions)
| Common Stock |
Additional Paid-In Capital |
Subscriptions Receivable |
Accumulated Other Comprehensive Income (Loss) |
Accumulated Deficit |
Treasury Stock |
Total |
||||||||||||||||||||||
| December 31, 2004 |
$ | 3,865 | $ | 41 | $ | (8 | ) | $ | (13 | ) | $ | (1,861 | ) | $ | (68 | ) | $ | 1,956 | ||||||||||
| Net income |
— | — | — | — | 90 | — | 90 | |||||||||||||||||||||
| Other comprehensive income, net of tax |
— | — | — | 17 | — | — | 17 | |||||||||||||||||||||
| Options exercised |
4 | 1 | — | — | — | (1 | ) | 4 | ||||||||||||||||||||
| Dividends and other distributions |
— | — | — | — | (22 | ) | — | (22 | ) | |||||||||||||||||||
| 401(k) plan and profit sharing stock |
5 | — | — | — | — | — | 5 | |||||||||||||||||||||
| Options and restricted stock granted |
— | 9 | — | — | — | — | 9 | |||||||||||||||||||||
| Shareholder litigation settlement |
81 | — | — | — | — | — | 81 | |||||||||||||||||||||
| December 31, 2005 |
$ | 3,955 | $ | 51 | $ | (8 | ) | $ | 4 | $ | (1,793 | ) | $ | (69 | ) | $ | 2,140 | |||||||||||
| Net loss |
— | — | — | — | (333 | ) | — | (333 | ) | |||||||||||||||||||
| Other comprehensive income, net of tax |
— | — | — | 98 | — | — | 98 | |||||||||||||||||||||
| Adjustment to initially apply SFAS No. 158, net of tax benefit of $21 |
— | — | — | (35 | ) | — | — | (35 | ) | |||||||||||||||||||
| Options exercised |
5 | (5 | ) | — | — | — | — | — | ||||||||||||||||||||
| Dividends and other distributions |
— | — | — | — | (9 | ) | — | (9 | ) | |||||||||||||||||||
| 401(k) plan and profit sharing stock |
3 | — | — | — | — | — | 3 | |||||||||||||||||||||
| Options and restricted stock granted |
— | 8 | — | — | — | — | 8 | |||||||||||||||||||||
| Equity issuance (Note 20) |
185 | (7 | ) | — | — | — | — | 178 | ||||||||||||||||||||
| Equity conversion (Note 20) |
225 | (8 | ) | — | — | — | — | 217 | ||||||||||||||||||||
| December 31, 2006 |
$ | 4,373 | $ | 39 | $ | (8 | ) | $ | 67 | $ | (2,135 | ) | $ | (69 | ) | $ | 2,267 | |||||||||||
| Net income |
— | — | — | — | 264 | — | 264 | |||||||||||||||||||||
| Other comprehensive loss, net of tax |
— | — | — | (92 | ) | — | — | (92 | ) | |||||||||||||||||||
| Adjustment to initially apply FIN No. 48 |
— | — | — | — | 7 | — | 7 | |||||||||||||||||||||
| Subscriptions receivable |
— | — | 3 | — | — | — | 3 | |||||||||||||||||||||
| Options exercised |
1 | 2 | — | — | — | (2 | ) | 1 | ||||||||||||||||||||
| 401(k) plan and profit sharing stock |
1 | 3 | — | — | — | — | 4 | |||||||||||||||||||||
| Options and restricted stock granted |
— | 19 | — | — | — | — | 19 | |||||||||||||||||||||
| Equity issuance-LS Power (Note 3) |
3 | 2,030 | — | — | — | — | 2,033 | |||||||||||||||||||||
| Conversion from Illinois entity to Delaware entity (Note 20) |
(4,370 | ) | 4,370 | — | — | — | — | — | ||||||||||||||||||||
| December 31, 2007 |
$ | 8 | $ | 6,463 | $ | (5 | ) | $ | (25 | ) | $ | (1,864 | ) | $ | (71 | ) | $ | 4,506 | ||||||||||
See the notes to the consolidated financial statements
F-10
DYNEGY INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in millions)
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| Net income (loss) |
$ | 264 | $ | (333 | ) | $ | 90 | |||||
| Cash flow hedging activities, net: |
||||||||||||
| Unrealized mark-to-market gains (losses) arising during period, net |
(95 | ) | 95 | (70 | ) | |||||||
| Reclassification of mark-to-market (gains) losses to earnings, net |
(25 | ) | (17 | ) | 84 | |||||||
| Changes in cash flow hedging activities, net (net of tax benefit (expense) of $69, $(46) and $(8), respectively) |
(120 | ) | 78 | 14 | ||||||||
| Allocation to minority interest |
5 | — | — | |||||||||
| Total cash flow hedging activities |
(115 | ) | 78 | 14 | ||||||||
| Foreign currency translation adjustments |
4 | (1 | ) | 8 | ||||||||
| Minimum pension liability (net of tax benefit (expense) of zero, $(5) and $3, respectively) |
— | 10 | (5 | ) | ||||||||
| Amortization of unrecognized prior service cost and actuarial loss (net of tax expense of $9) |
18 | — | — | |||||||||
| Unrealized gain on securities, net: |
||||||||||||
| Unrealized gain on securities |
6 | 11 | — | |||||||||
| Reclassification adjustments for gains realized in net income (loss) |
(5 | ) | — | — | ||||||||
| Unrealized gains on securities (net of tax expenses of $1, $7, and zero, respectively) |
1 | 11 | — | |||||||||
| Other comprehensive income (loss), net of tax |
(92 | ) | 98 | 17 | ||||||||
| Comprehensive income (loss) |
$ | 172 | $ | (235 | ) | $ | 107 | |||||
See the notes to the consolidated financial statements
F-11
DYNEGY HOLDINGS INC.
(in millions)
| December 31, 2007 |
December 31, 2006 |
|||||||
| ASSETS |
||||||||
| Current Assets |
||||||||
| Cash and cash equivalents |
$ | 292 | $ | 243 | ||||
| Restricted cash and investments |
104 | 280 | ||||||
| Accounts receivable, net of allowance for doubtful accounts of $15 and $48, respectively |
428 | 263 | ||||||
| Accounts receivable, affiliates |
1 | 7 | ||||||
| Inventory |
199 | 194 | ||||||
| Assets from risk-management activities |
358 | 701 | ||||||
| Deferred income taxes |
30 | 48 | ||||||
| Prepayments and other current assets |
145 | 92 | ||||||
| Assets held for sale (Note 4) |
57 | — | ||||||
| Total Current Assets |
1,614 | 1,828 | ||||||
| Property, Plant and Equipment |
10,689 | 6,473 | ||||||
| Accumulated depreciation |
(1,672 | ) | (1,522 | ) | ||||
| Property, Plant and Equipment, Net |
9,017 | 4,951 | ||||||
| Other Assets |
||||||||
| Unconsolidated investments |
18 | — | ||||||
| Restricted cash and investments |
1,221 | 83 | ||||||
| Assets from risk-management activities |
55 | 16 | ||||||
| Long-term accounts receivable, affiliate |
— | 781 | ||||||
| Goodwill |
438 | — | ||||||
| Intangible assets |
497 | 347 | ||||||
| Deferred income taxes |
6 | 12 | ||||||
| Other long-term assets |
241 | 118 | ||||||
| Total Assets |
$ | 13,107 | $ | 8,136 | ||||
| LIABILITIES AND STOCKHOLDER’S EQUITY |
||||||||
| Current Liabilities |
||||||||
| Accounts payable |
$ | 291 | $ | 172 | ||||
| Accrued interest |
56 | 66 | ||||||
| Accrued liabilities and other current liabilities |
202 | 230 | ||||||
| Liabilities from risk-management activities |
397 | 629 | ||||||
| Notes payable and current portion of long-term debt |
51 | 68 | ||||||
| Liabilities held for sale (Note 4) |
2 | — | ||||||
| Total Current Liabilities |
999 | 1,165 | ||||||
| Long-term debt |
5,739 | 2,990 | ||||||
| Long-term debt to affiliates |
200 | 200 | ||||||
| Long-Term Debt |
5,939 | 3,190 | ||||||
| Other Liabilities |
||||||||
| Liabilities from risk-management activities |
116 | 35 | ||||||
| Deferred income taxes |
1,052 | 325 | ||||||
| Other long-term liabilities |
381 | 385 | ||||||
| Total Liabilities |
8,487 | 5,100 | ||||||
| Minority Interest |
23 | — | ||||||
| Commitments and Contingencies (Note 19) |
||||||||
| Stockholder’s Equity |
||||||||
| Capital Stock, $1 par value, 1,000 shares authorized at December 31, 2007 and December 31, 2006, respectively |
— | — | ||||||
| Additional paid-in capital |
5,684 | 3,543 | ||||||
| Affiliate receivable |
(825 | ) | — | |||||
| Accumulated other comprehensive income (loss), net of tax |
(25 | ) | 67 | |||||
| Accumulated deficit |
(237 | ) | (574 | ) | ||||
| Total Stockholder’s Equity |
4,597 | 3,036 | ||||||
| Total Liabilities and Stockholder’s Equity |
$ | 13,107 | $ | 8,136 | ||||
See the notes to the consolidated financial statements
F-12
DYNEGY HOLDINGS INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| Revenues |
$ | 3,103 | $ | 1,770 | $ | 2,017 | ||||||
| Cost of sales, exclusive of depreciation shown separately below |
(2,013 | ) | (1,136 | ) | (2,126 | ) | ||||||
| Depreciation and amortization expense |
(325 | ) | (217 | ) | (208 | ) | ||||||
| Impairment and other charges |
— | (119 | ) | (40 | ) | |||||||
| Gain (loss) on sale of assets, net |
43 | 3 | (1 | ) | ||||||||
| General and administrative expenses |
(184 | ) | (193 | ) | (375 | ) | ||||||
| Operating income (loss) |
624 | 108 | (733 | ) | ||||||||
| Earnings (losses) from unconsolidated investments |
6 | (1 | ) | — | ||||||||
| Interest expense |
(384 | ) | (375 | ) | (383 | ) | ||||||
| Debt conversion costs |
— | (204 | ) | — | ||||||||
| Other income and expense, net |
53 | 51 | 15 | |||||||||
| Minority interest expense |
(7 | ) | — | — | ||||||||
| Income (loss) from continuing operations before income taxes |
292 | (421 | ) | (1,101 | ) | |||||||
| Income tax (expense) benefit |
(116 | ) | 125 | 374 | ||||||||
| Income (loss) from continuing operations |
176 | (296 | ) | (727 | ) | |||||||
| Income (loss) from discontinued operations, net of tax (expense) benefit of ($92), $12 and $(437), respectively (Note 4) |
148 | (12 | ) | 813 | ||||||||
| Income (loss) before cumulative effect of change in accounting principles |
324 | (308 | ) | 86 | ||||||||
| Cumulative effect of change in accounting principles, net of tax benefit (expense) of zero, zero and $2, respectively (Note 2) |
— | — | (5 | ) | ||||||||
| Net income (loss) |
$ | 324 | $ | (308 | ) | $ | 81 | |||||
See the notes to the consolidated financial statements
F-13
DYNEGY HOLDINGS INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||||||
| Net income (loss) |
$ | 324 | $ | (308 | ) | $ | 81 | |||||
| Adjustments to reconcile income (loss) to net cash flows from operating activities: |
||||||||||||
| Depreciation and amortization |
333 | 263 | 278 | |||||||||
| Impairment and other charges |
— | 155 | 40 | |||||||||
| (Earnings) losses from unconsolidated investments, net of cash distributions |
(6 | ) | 1 | 74 | ||||||||
| Risk-management activities |
(50 | ) | (87 | ) | 46 | |||||||
| Gain on sale of assets, net |
(267 | ) | (5 | ) | (1,096 | ) | ||||||
| Deferred taxes |
179 | (138 | ) | 37 | ||||||||
| Cumulative effect of change in accounting principles (Note 2) |
— | — | 5 | |||||||||
| Reserve for doubtful accounts |
— | (35 | ) | 1 | ||||||||
| Independence toll settlement charge (Note 14) |
— | — | 169 | |||||||||
| Legal and settlement charges |
26 | (2 | ) | 38 | ||||||||
| Sterlington toll settlement charge (Note 4) |
— | — | 364 | |||||||||
| Sithe Subordinated Debt exchange charge (Note 15) |
— | 36 | — | |||||||||
| Debt conversion costs |
— | 204 | — | |||||||||
| Other |
39 | 69 | 8 | |||||||||
| Changes in working capital, net of acquired businesses: |
||||||||||||
| Accounts receivable |
(114 | ) | 391 | (136 | ) | |||||||
| Inventory |
(13 | ) | 8 | (91 | ) | |||||||
| Prepayments and other assets |
(37 | ) | 102 | 151 | ||||||||
| Accounts payable and accrued liabilities |
(1 | ) | (873 | ) | (2 | ) | ||||||
| Changes in non-current assets |
(56 | ) | 11 | (15 | ) | |||||||
| Changes in non-current liabilities |
11 | 3 | 24 | |||||||||
| Net cash provided by (used in) operating activities |
368 | (205 | ) | (24 | ) | |||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||
| Capital expenditures |
(379 | ) | (155 | ) | (195 | ) | ||||||
| Proceeds from asset sales, net |
558 | 224 | 2,393 | |||||||||
| Unconsolidated investments |
13 | — | — | |||||||||
| Business acquisitions, net of cash acquired |
16 | — | 26 | |||||||||
| Proceeds from exchange of unconsolidated investments, net of cash acquired (Note 3 and |
— | 165 | — | |||||||||
| (Increase) decrease in restricted cash |
(871 | ) | 121 | (353 | ) | |||||||
| Affiliate transactions |
(24 | ) | (6 | ) | (36 | ) | ||||||
| Other investing, net |
(1 | ) | 8 | 4 | ||||||||
| Net cash provided by (used in) investing activities |
(688 | ) | 357 | 1,839 | ||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||
| Net proceeds from long-term borrowings |
2,758 | 1,071 | 600 | |||||||||
| Repayments of borrowings |
(2,045 | ) | (1,930 | ) | (1,432 | ) | ||||||
| Borrowings from (repayments to) affiliate, net |
— | (120 | ) | 120 | ||||||||
| Debt conversion costs |
— | (204 | ) | — | ||||||||
| Dividends to affiliates |
(342 | ) | (50 | ) | — | |||||||
| Other financing, net |
(2 | ) | (2 | ) | (22 | ) | ||||||
| Net cash provided by (used in) financing activities |
369 | (1,235 | ) | (734 | ) | |||||||
| Net increase (decrease) in cash and cash equivalents |
49 | (1,083 | ) | 1,081 | ||||||||
| Cash and cash equivalents, beginning of period |
243 | 1,326 | 245 | |||||||||
| Cash and cash equivalents, end of period |
$ | 292 | $ | 243 | $ | 1,326 | ||||||
See the notes to the consolidated financial statements
F-14
DYNEGY HOLDINGS INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY
(in millions)
| Additional Paid-In Capital |
Affiliate Receivable |
Accumulated Other Comprehensive Income (Loss) |
Accumulated Deficit |
Total |
||||||||||||||||
| December 31, 2004 |
$ | 3,445 | $ | — | $ | (13 | ) | $ | (347 | ) | $ | 3,085 | ||||||||
| Net income |
— | — | — | 81 | 81 | |||||||||||||||
| Contribution of Sithe to DHI |
149 | — | — | — | 149 | |||||||||||||||
| Other comprehensive income, net of tax |
— | — | 17 | — | 17 | |||||||||||||||
| Options exercised |
(1 | ) | — | — | — | (1 | ) | |||||||||||||
| December 31, 2005 |
$ | 3,593 | $ | — | $ | 4 | $ | (266 | ) | $ | 3,331 | |||||||||
| Net loss |
— | — | — | (308 | ) | (308 | ) | |||||||||||||
| Other comprehensive income, net of tax |
— | — | 98 | — | 98 | |||||||||||||||
| Adjustment to initially apply SFAS No. 158, net of tax benefit of $21 |
— | — | (35 | ) | — | (35 | ) | |||||||||||||
| Dividends to affiliates |
(50 | ) | — | — | — | (50 | ) | |||||||||||||
| December 31, 2006 |
$ | 3,543 | $ | — | $ | 67 | $ | (574 | ) | $ | 3,036 | |||||||||
| Net income |
— | — | — | 324 | 324 | |||||||||||||||
| Other comprehensive loss, net of tax |
— | — | (92 | ) | — | (92 | ) | |||||||||||||
| Adjustment to initially apply FIN No. 48 |
— | — | — | 13 | 13 | |||||||||||||||
| Contribution of Contributed Entities and Sandy Creek to DHI |
2,483 | — | — | — | 2,483 | |||||||||||||||
| Reclassification of affiliate receivable |
— | (825 | ) | — | — | (825 | ) | |||||||||||||
| Dividends to affiliates |
(342 | ) | — | — | — | (342 | ) | |||||||||||||
| December 31, 2007 |
$ | 5,684 | $ | (825 | ) | $ | (25 | ) | $ | (237 | ) | $ | 4,597 | |||||||
See the notes to the consolidated financial statements
F-15
DYNEGY HOLDINGS INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in millions)
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| Net income (loss) |
$ | 324 | $ | (308 | ) | $ | 81 | |||||
| Cash flow hedging activities, net: |
||||||||||||
| Unrealized mark-to-market gains (losses) arising during period, net |
(95 | ) | 95 | (70 | ) | |||||||
| Reclassification of mark-to-market (gains) losses to earnings, net |
(25 | ) | (17 | ) | 84 | |||||||
| Changes in cash flow hedging activities, net (net of tax benefit (expense) of $69, $(46) and $(8), respectively) |
(120 | ) | 78 | 14 | ||||||||
| Allocation to minority interest |
5 | — | — | |||||||||
| Total cash flow hedging activities |
(115 | ) | 78 | 14 | ||||||||
| Foreign currency translation adjustments |
4 | (1 | ) | 8 | ||||||||
| Minimum pension liability (net of tax benefit (expense) of zero, $(5) and $3, respectively) |
— | 10 | (5 | ) | ||||||||
| Amortization of unrecognized prior service cost and actuarial loss (net of tax expense of $9) |
18 | — | — | |||||||||
| Unrealized gain on securities, net: |
||||||||||||
| Unrealized gain on securities |
6 | 11 | — | |||||||||
| Reclassification adjustments for gains realized in net income (loss) |
(5 | ) | — | — | ||||||||
| Unrealized gains on securities (net of tax expense of $1, $7, and zero, respectively) |
1 | 11 | — | |||||||||
| Other comprehensive income (loss), net of tax |
(92 | ) | 98 | 17 | ||||||||
| Comprehensive income (loss) |
$ | 232 | $ | (210 | ) | $ | 98 | |||||
See the notes to the consolidated financial statements
F-16
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1—Organization and Operations
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 and natural gas transportation contracts and legacy 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. As described below, our natural gas liquids business, which was conducted through DMSLP and its subsidiaries, was sold to Targa Resources, Inc. (“Targa”) on October 31, 2005.
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.
In addition to our operating generation facilities, 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 Energy Associates, LLC (“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 Sandy Creek Holdings, LLC (“SCH”), which owns a 75 percent undivided interest in Sandy Creek Energy Station (“the Sandy Creek Project”), 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, LLC, a newly formed Delaware limited liability company (“DLS Power Holdings”), 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, which is included in Other in our segment disclosures.
Note 2—Summary of Significant Accounting Policies
Use of Estimates. The preparation of consolidated financial statements in conformity with generally accepted accounting principles (“GAAP”) requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (i) developing fair value assumptions, including estimates of future cash flows and discount rates, (ii) analyzing tangible and intangible assets for possible impairment, (iii) estimating the useful lives of our assets, (iv) assessing future tax exposure and the realization of deferred tax assets, (v) determining amounts to accrue for contingencies, guarantees and indemnifications, (vi) estimating various factors used to value our pension assets and liabilities and (vii) determining the primary beneficiary of certain variable interest entities (“VIEs”) from a set of related parties. Actual results could differ materially from our estimates.
F-17
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Principles of Consolidation. The accompanying consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries and VIEs for which we are the primary beneficiary and our proportionate share of assets, liabilities and expenses directly related to an undivided interest in a coal-fired power generation facility under construction. Intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to prior-period amounts to conform with current-period presentation.
Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid short-term investments with original maturities of three months or less.
Restricted Cash. Restricted cash represents cash that is not readily available for general purpose cash needs. Restricted cash is classified as a current or long-term asset based on the timing of when the cash is expected to be used or when the restrictions are expected to lapse. We include all changes in restricted cash in investing cash flows on the consolidated statements of cash flows. Please read Note 15—Debt—Restricted Cash and Investments for further discussion.
Allowance for Doubtful Accounts. We establish provisions for losses on accounts receivable if it becomes probable we will not collect all or part of outstanding balances. We review collectibility and establish or adjust our allowance as necessary. We primarily use a percent of balance methodology and methodologies involving historical levels of write-offs. The specific identification method is also used in certain circumstances.
Unconsolidated Investments. We use the equity method of accounting for investments in affiliates over which we exercise significant influence, generally occurring in ownership interests of 20 percent to 50 percent, and also occurring in lesser ownership percentages due to voting rights or other factors and VIEs where we are not the primary beneficiary. Our share of net income (loss) from these affiliates is reflected in the consolidated statements of operations as earnings (losses) from unconsolidated investments. Any excess of our investment in affiliates, as compared to our share of the underlying equity that is not recognized as goodwill, is amortized over the estimated economic service lives of the underlying assets, or, in the instances where the useful lives can not be determined, are assessed each reporting period for impairment or to determine if the useful life can be estimated. All investments in unconsolidated affiliates are periodically assessed for other-than-temporary declines in value, with write-downs recognized in earnings from unconsolidated investments in the consolidated statements of operations.
Please read Note 5—Restructuring and Impairment Charges for a discussion of impairment charges we recognized in 2006 and 2005.
Available-for-Sale Securities. For securities classified as available-for-sale that have readily determinable fair values, the change in the unrealized gain or loss, net of deferred income tax, is recorded as a separate component of accumulated other comprehensive income (loss) in the consolidated statements of comprehensive income (loss). Realized gains and losses on investment transactions are determined using the specific identification method.
Inventory. Our natural gas, coal, emissions allowances and fuel oil inventories are carried at the lower of weighted average cost or at market. Our materials and supplies inventory is carried at the lower of cost or market using the specific identification method. We use the average cost method to determine cost.
We adopted EITF Issue 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”, in the fourth quarter 2005. Accordingly, we account for exchanges of inventory with the same counterparty as one transaction at fair value.
F-18
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
We may opportunistically sell emissions allowances, subject to certain regulatory limitations and restrictions contained in our Midwest consent decree, or hold them in inventory until they are needed. In the past, we have sold emission allowances that relate to future periods. To the extent the proceeds received from the sale of such allowances exceed our cost, we defer the associated gain until the period to which the allowance relates, as we may be required to purchase emissions allowances in future periods. As of December 31, 2007, we had aggregate deferred gains of $9 million, all of which is included in Other long-term liabilities on our consolidated balance sheets. As of December 31, 2006, we had aggregate deferred gains of $20 million, consisting of $11 million included in Accrued liabilities and other current liabilities and $9 million included in Other long-term liabilities, respectively, on our consolidated balance sheets. We recognized $13 million, $16 million and $17 million in revenue in 2007, 2006 and 2005, respectively, related to sales of emissions credits.
Property, Plant and Equipment. Property, plant and equipment, which consists principally of power generating facilities, including capitalized interest, is recorded at historical cost. Expenditures for major replacements, renewals and major maintenance are capitalized and depreciated over the expected maintenance cycle. We consider major maintenance to be expenditures incurred on a cyclical basis to maintain and prolong the efficient operation of our assets. Expenditures for repairs and minor renewals to maintain assets in operating condition are expensed. Depreciation is provided using the straight-line method over the estimated economic service lives of the assets, ranging from 3 to 40 years. Depreciation rates are applied to functional groups of assets having similar economic characteristics. The estimated economic service lives of our functional asset groups are as follows:
| Asset Group |
Range of Years | |
| Power generation facilities |
20 to 40 | |
| Buildings and improvements |
10 to 39 | |
| Office and miscellaneous equipment |
3 to 20 |
Gains and losses on sales of individual assets or asset groups are reflected in Gain (loss) on sale of assets, net, in the consolidated statements of operations. We assess the carrying value of our property, plant and equipment in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”). If an impairment is indicated, the amount of the impairment loss recognized would be determined by the amount by which the book value exceeds the estimated fair value of the assets. The estimated fair value may include estimates based upon discounted cash-flow projections, recent comparable market transactions or quoted prices to determine if an impairment loss is required. For assets identified as held for sale, the book value is compared to the estimated sales price less costs to sell.
Please read Note 5—Restructuring and Impairment Charges for a discussion of impairment charges we recognized in 2006 and 2005.
Goodwill and Other Intangible Assets. Goodwill represents, at the time of an acquisition, the amount of purchase price paid in excess of the fair value of net assets acquired. We follow the guidance set forth in SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”), when assessing the carrying value of our goodwill. Accordingly, we evaluate our goodwill for impairment on an annual basis on November 1st, and when events warrant an assessment. Our evaluation is based, in part, on our estimate of future cash flows. The estimation of fair value is highly subjective, inherently imprecise and can change materially from period to period based on, among other things, an assessment of market conditions, projected cash flows and discount rate. We have completed our goodwill impairment analysis for 2007 and no impairment was indicated.
F-19
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Intangible assets represent the fair value of assets, apart from goodwill, that arise from contractual rights or other legal rights. In accordance with SFAS No. 141, “Business Combinations” (“SFAS No. 141”), we record only those intangible assets that are distinctly separable from goodwill and can be sold, transferred, licensed, rented, or otherwise exchanged in the open market. Additionally, we recognize as intangible assets those assets that can be exchanged in combination with other rights, contracts, assets or liabilities.
In accordance with SFAS No. 142, we initially record and measure intangible assets based on the fair value of those rights transferred in the transaction in which the asset was acquired. Those measurements are based on quoted market prices for the asset, if available, or measurement techniques based on the best information available such as a present value of future cash flows measurement. Present value measurement techniques involve judgments and estimates made by management about prices, cash flows, discount factors and other variables, and the actual value realized from those assets could vary materially from these judgments and estimates. We amortize our definite-lived intangible assets based on the useful life of the respective asset as measured by the life of the underlying contract or contracts. Intangible assets that are not subject to amortization are subjected to impairment testing on an annual basis or when a triggering event occurs, and an impairment loss is recognized if the carrying amount of an intangible asset exceeds its fair value.
Asset Retirement Obligations. We record the present value of our legal obligations to retire tangible, long-lived assets on our balance sheets as liabilities when the liability is incurred. Significant judgment is involved in estimating future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. Effective December 31, 2005, we adopted the provisions of FIN No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN No. 47”) which is an interpretation of SFAS No. 143, “Asset Retirement Obligations” (“SFAS No. 143”). Under the provisions of FIN No. 47, we recorded additional AROs to recognize the costs of the future removal of asbestos containing materials from certain of our power generation facilities. As a result, we recorded an after-tax charge of $5 million, which is included in the consolidated statements of operations as a cumulative effect of change in accounting principles. FIN No. 47, if it had been adopted as of January 1, 2005, would have had no material effect on our results of operations or earnings per share.
In addition to the AROs discussed above, our AROs relate to activities such as ash pond and landfill capping, dismantlement of power generation facilities, closure and post-closure costs, environmental testing, remediation, monitoring and land and equipment lease obligations. A summary of changes in our AROs is as follows:
| Year Ended December 31, |
|||||||||||
| 2007 |
2006 |
2005 |
|||||||||
| (in millions) | |||||||||||
| Beginning of year |
$ | 56 | $ | 56 | $ | 46 | |||||
| New AROs (1) |
— | 6 | 1 | ||||||||
| Accretion expense |
8 | 6 | 4 | ||||||||
| Acquisition of the Contributed Entities |
43 | — | — | ||||||||
| Sale of DMSLP |
— | — | (11 | ) | |||||||
| Implementation of FIN No. 47 |
— | — | 16 | ||||||||
| Revision of previous estimate (2) |
— | (12 | ) | — | |||||||
| End of year |
$ | 107 | $ | 56 | $ | 56 | |||||
| (1) | During 2006, we recorded additional AROs in the amount of $6 million related to our obligation to remediate a landfill located at our Danskammer generating facility. During 2005, we determined we would be obligated to dismantle our Danskammer generating facility upon its retirement. Therefore, we recorded |
F-20
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| an ARO in the amount of $1 million. There were no additional AROs, other than those acquired from LS Power or recorded under the provisions of FIN No. 47, recorded or settled during 2007 or 2006. |
| (2) | During 2006, we revised our ARO obligation downward by $12 million based on revised estimates of the costs to remediate ash ponds at certain of our coal fired generating facilities. |
We may have additional potential retirement obligations for dismantlement of power generation facilities. Our current intent is to maintain these facilities in a manner such that they will be operated indefinitely. As such, we cannot estimate any potential retirement obligations associated with these assets. Liabilities will be recorded in accordance with SFAS No. 143 at the time we are able to estimate these AROs.
Contingencies, Commitments, Guarantees and Indemnifications. We are involved in numerous lawsuits, claims, proceedings and tax-related audits in the normal course of our operations. In accordance with SFAS No. 5, “Accounting for Contingencies” (“SFAS No. 5”), we record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss contingencies on an ongoing basis to ensure that we have appropriate reserves recorded on our consolidated balance sheets as required by SFAS No. 5. These reserves are based on estimates and judgments made by management with respect to the likely outcome of these matters, considering any applicable insurance coverage for litigation matters, and are adjusted as circumstances warrant. Our estimates and judgment could change based on new information, changes in laws or regulations, changes in management’s plans or intentions, the outcome of legal proceedings, settlements or other factors. If different estimates and judgments were applied with respect to these matters, it is likely that reserves would be recorded for different amounts. Actual results could vary materially from these estimates and judgments.
Liabilities for environmental contingencies are recorded when an environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability. These assumptions involve the judgments and estimates of management, and any changes in assumptions could lead to increases or decreases in our ultimate liability, with any such changes recognized immediately in earnings.
We follow the guidance of FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FIN No. 45”) for disclosures and accounting of various guarantees and indemnifications entered into during the course of business. When a guarantee or indemnification subject to FIN No. 45 is entered into, an estimated fair value of the underlying guarantee or indemnification is recorded. Some guarantees and indemnifications could have significant financial impact under certain circumstances, however management also considers the probability of such circumstances occurring when estimating the fair value. Actual results may materially differ from the estimated fair value of such guarantees and indemnifications.
Revenue Recognition and Valuation of Risk Management Assets and Liabilities. We earn revenue from our facilities in three primary ways: (i) sale of energy generated by our facilities; (i) sale of ancillary services, which are the products of a generation facility that support the transmission grid operation, allow generation to follow real-time changes in load, and provide emergency reserves for major changes to the balance of generation and load; and (iii) sale of capacity. We recognize revenue from these transactions when the product or service is delivered to a customer, unless they meet the definition of a derivative, as defined by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (“SFAS No. 133”). Please read “—Derivative Instruments—Generation” for further discussion of the accounting for these types of transactions.
F-21
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Derivative Instruments—Generation. We enter into commodity contracts that meet the definition of a derivative under SFAS No. 133. These contracts are often entered into to mitigate or eliminate market and financial risks associated with our generation business. These contracts include forward contracts, which commit us to sell commodities in the future; futures contracts, which are generally exchange-traded standard commitments to purchase or sell a commodity; option contracts, which convey the right to buy or sell a commodity; and swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined quantity. SFAS No. 133 proscribes three different ways to account for these types of contracts: (i) as an accrual contract, if the criteria for the “normal purchase normal sale” exception are met and documented; (ii) as a cash flow or fair value hedge, if the specified criteria are met and documented; or (iii) as a mark-to-market contract with changes in fair value recognized in current period earnings. All derivative commodity contracts that do not qualify for the normal purchase normal sale exception are recorded at fair value in risk management assets and liabilities on the consolidated balance sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement. If the derivative commodity contract has been designated as a cash flow hedge, the changes in fair value are recognized in earnings concurrent with the hedged item. Changes in the fair value of derivative commodity contracts that are not designated as cash flow hedges are recorded currently in earnings.
In order to estimate the fair value of our derivative contracts, we use a liquidation value approach and assume that the ability to transact business in the market remains at historical levels. The estimated fair value of the portfolio is computed by multiplying all existing positions in the portfolio by estimated prices, reduced by a time value of money adjustment and reserves for credit and price. The estimated prices in this valuation are based either on (i) prices obtained from market quotes, when there are an adequate number of quotes to consider the period liquid, or, (ii) if market quotes are unavailable or the market is not considered liquid, prices from a proprietary model which incorporates forward energy prices derived from market quotes and values from previously executed transactions. The amounts recorded as revenue change as these estimates are revised to reflect actual results and changes in market conditions or other factors, many of which are beyond our control. Volatility in commodity prices, interest rates and, if applicable, foreign exchange rates, can significantly impact the valuation of these derivative contracts.
Previously, we designated many commodity contracts that met the definition of a derivative as cash flow hedges. Beginning on April 2, 2007, we chose to cease designating such contracts as cash flow hedges, and thus apply mark-to-market accounting treatment prospectively.
Cash inflows and cash outflows associated with the settlement of risk management activities are recognized in net cash provided by (used in) operating activities on the consolidated statements of cash flows.
Derivative Instruments—Financing Activities. We are exposed to changes in interest rates through our variable and fixed rate debt. In order to manage our interest rate risk, we enter into interest rate swap agreements.
Income Taxes. We follow the guidance in SFAS No. 109, “Accounting for Income Taxes” (“SFAS No. 109”), which requires that we use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.
As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing tax and accounting treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheets.
F-22
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50 percent) that some portion or all of the deferred tax assets will not be realized, we must establish a valuation allowance. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.
Because we operate and sell power in many different states, our effective annual state income tax rate will vary from period to period as a result of changes in our sales profile by state, as well as jurisdictional and legislative changes by state. As a result, changes in our estimated effective annual state income tax rate can have a significant impact on our measurement of temporary differences.
Management believes future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize deferred tax assets for which no reserve has been established. While we have considered these factors in assessing the need for a valuation allowance, there is no assurance that a valuation allowance would not need to be established in the future if information about future years changes. Any change in the valuation allowance would impact our income tax benefit (expense) and net income (loss) in the period in which such a determination is made.
On January 1, 2007, we adopted FIN No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN No. 48”), which provides clarification of SFAS No. 109 with respect to the recognition of income tax benefits of uncertain tax positions in the financial statements. We recognize accrued interest expense and penalties related to unrecognized tax benefits as income tax expense.
Please read Note 17—Income Taxes for further discussion of our accounting for income taxes, adoption of FIN No. 48 and change in our valuation allowance.
Earnings Per Share. Basic earnings per share represents the amount of earnings for the period available to each share of common stock outstanding during the period. Diluted earnings per share amounts include the effect of issuing shares of common stock for outstanding stock options and performance based stock awards under the treasury stock method if including such potential common shares is dilutive.
Foreign Currency. For subsidiaries whose functional currency is not the U.S. Dollar, assets and liabilities are translated at year-end exchange rates, and revenues and expenses are translated at monthly average exchange rates. Translation adjustments for the asset and liability accounts are included as a separate component of accumulated other comprehensive income (loss) in stockholders’ equity. Currency transaction gains and losses are recorded in other income and expense, net, in the consolidated statements of operations. We recorded gains (losses) of approximately $(6) million, $1 million and $(4) million for the years ended December 31, 2007, 2006 and 2005, respectively.
Employee Stock Options. On January 1, 2003, we adopted the fair-value based method of accounting for stock-based employee compensation under SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”), and used the prospective method of transition as described under SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure” (“SFAS No. 148”). Under the prospective method of transition, all stock options granted after January 1, 2003 were accounted for on a fair value basis. Options granted prior to January 1, 2003 continued to be accounted for using the intrinsic value method. Accordingly, for options granted prior to January 1, 2003, compensation expense was not reflected for employee stock options unless they were granted at an exercise price lower than market value on the grant date. We granted in-the-money options in the past and recognized compensation expense over the applicable vesting periods. No in-the-money stock options have been granted since 1999.
F-23
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment” (“SFAS No. 123(R)”) which revises SFAS No. 123. SFAS No. 123(R) requires all companies to expense the fair value of employee stock options and other forms of stock-based compensation. We adopted SFAS No. 123(R) effective January 1, 2006, using the modified prospective transition method permitted under this pronouncement. Our cumulative effect of implementing this standard, which consists entirely of a forfeiture adjustment, was less than $1 million after tax.
In November 2005, the FASB issued FSP No. 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards”. We have adopted the short-cut method to calculate the beginning balance of the APIC pool of the excess tax benefit, and to determine the subsequent impact on the APIC pool and consolidated statements of cash flows of the tax effects of employee stock-based compensation awards that were outstanding upon our adoption of FAS 123(R). Utilizing the short-cut method, we have determined that we have a “Pool of Windfall” tax benefits that can be utilized to offset future shortfalls that may be incurred.
The adoption of SFAS No. 123(R) had no material impact on our consolidated statements of operations, our consolidated statements of cash flows and basic and diluted income (loss) per share for the years ended December 31, 2007 or 2006, compared to amounts that would have been reported pursuant to our previous accounting. Had compensation cost for all stock options granted prior to 2003 been determined on a fair value basis consistent with SFAS No. 123, Dynegy’s and DHI’s net income and Dynegy’s basic and diluted earnings per share amounts would have approximated the following pro forma amounts for the year ended December 31, 2005.
| Year Ended December 31, 2005 |
||||||||
| (in millions, except per share data) |
||||||||
| Dynegy |
DHI |
|||||||
| Net income as reported |
$ | 90 | $ | 81 | ||||
| Add: Stock-based employee compensation expense included in reported net income, net of related tax effects |
6 | 6 | ||||||
| Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects |
(8 | ) | (8 | ) | ||||
| Pro forma net income |
$ | 88 | $ | 79 | ||||
| Earnings per share: |
||||||||
| Basic—as reported |
$ | 0.18 | N/A | |||||
| Basic—pro forma |
$ | 0.17 | N/A | |||||
| Diluted—as reported |
$ | 0.18 | N/A | |||||
| Diluted—pro forma |
$ | 0.17 | N/A | |||||
Please read Note 20—Capital Stock for further discussion of our share-based compensation and expense recognized for 2007, 2006 and 2005.
Minority Interest. Minority interest on the consolidated balance sheets includes third party investments in entities that we consolidate, but do not wholly own. The net pre-tax results attributed to minority interest holders in consolidated entities are included in minority interest income (expense) in the consolidated statements of operations. The net after-tax other comprehensive income amounts attributed to minority interest holders in consolidated entities are included in the consolidated statements of comprehensive income (loss).
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DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
We allocate net income and other comprehensive income to minority interest owners in Plum Point based on the amounts that would be distributed to the equity interest owners in accordance with the terms of the underlying agreement. To the extent that the losses applicable to the minority interest owners would cause the minority interest owners to exceed their obligation to make good such losses, the amounts are reallocated back to us. We will recover any such losses prior to allocating future earnings to the minority interest owners. For the year ended December 31, 2007, we have absorbed approximately $1 million of losses related to net income and $15 million of losses related to other comprehensive income in excess of the minority interest holders’ funding commitments.
Accounting Principles Not Yet Adopted
SFAS No. 157. On September 15, 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements. Accordingly, SFAS No. 157 does not require any new fair value measurements; however for some entities the application of SFAS No. 157 will change current practice. On February 12, 2008, the FASB issued FASB Staff Position No. FAS 157-2 (“FSP SFAS No. 157-2”), which defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, with respect to non-financial assets and non-financial liabilities which are not recognized or disclosed at fair value in the financial statements on a recurring basis. Therefore, we will defer application of SFAS No. 157 to such non-financial assets and non-financial liabilities until January 1, 2009. With respect to items outside the scope of FSP SFAS No. 157-2, we will adopt SFAS No. 157 for the fiscal year beginning January 1, 2008 and we do not expect to record a cumulative effect upon the adoption of this standard.
SFAS No. 159. On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure eligible items at fair value at specified election dates. A business entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. We will adopt SFAS No. 159 for the fiscal year beginning January 1, 2008. We do not expect to elect the fair value option for any eligible items and therefore do not expect SFAS No. 159 to have an impact on our financial statements.
SFAS No. 141(R). On December 4, 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) requires the acquiring entity in a business combination to recognize the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS No. 141(R) is effective for fiscal years beginning on or after December 15, 2008. We are currently evaluating the impact of this statement on our financial statements.
SFAS No. 160. On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 requires ownership interests in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity; the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of income; changes in a parent’s ownership
F-25
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently; and any retained noncontrolling equity investment in the former subsidiary be initially measured at fair value. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. We are currently evaluating the impact of this statement on our financial statements.
Note 3—Business Combinations and Acquisitions
LS Power Business Combination. On March 29, 2007, at a special meeting of the shareholders of 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 (“Merger Sub”), 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 with and into Dynegy Illinois (together with the Merger Agreement, the “Merger”).
Upon the closing of the Merger, 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 the LS Contributing Entities transferred to Dynegy all of the interests owned by them in entities that own eleven power generation facilities (the “Contributed Entities”).
As part of the Merger transactions, 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. In connection with the formation of DLS Power Holdings, LS Associates formed DLS Power Development Company, LLC, a Delaware limited liability company (“DLS Power Development”). LS Associates and Dynegy each now own 50 percent of the membership interests in DLS Power Development.
The aggregate purchase price was comprised of (i) $100 million cash, (ii) 340 million shares of the Class B common stock of Dynegy, (iii) the issuance of a promissory note in the aggregate principal amount of $275 million (the “Note”) (which was simultaneously issued and repaid in full without interest or prepayment penalty), (iv) the issuance of an additional $70 million of project-related debt (the “Griffith Debt”) (which was simultaneously issued and repaid in full without interest or prepayment penalty) via an indirect wholly owned subsidiary, and (v) transaction costs of approximately $52 million, approximately $8 million of which were paid in 2006. The Class B common stock issued by Dynegy was valued at $5.98 per share, which represents the average closing price of Dynegy’s common stock on the New York Stock Exchange for the two days prior to, including, and two days subsequent to the September 15, 2006 public announcement of the Merger, or approximately $2,033 million. Dynegy funded the cash payment and the repayment of the Note and the Griffith Debt using cash on hand and borrowings by DHI (and subsequent permitted distributions to Dynegy) of (i) an aggregate $275 million under the Revolving Facility (as defined below) and (ii) an aggregate $70 million under the new Term Loan B (as defined below). Please read Note 15—Debt—Fifth Amended and Restated Credit Facility for further discussion. We paid a premium over the fair value of the net tangible and identified intangible assets acquired due to the (i) scale and diversity of assets acquired in key regions of the United States; (ii) financial stability, and (iii) proven nature of the LS Power asset development platform that was subsequently contributed to DLS Power Holdings and DLS Power Development.
F-26
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The application of purchase accounting under SFAS No. 141 requires that the total purchase price be allocated to the fair value of assets acquired and liabilities assumed based on their fair values at the acquisition date, with amounts exceeding the fair values being recorded as goodwill in accordance with SFAS No. 142. The allocation process requires an analysis of acquired fixed assets, contracts, and contingencies to identify and record the fair value of all assets acquired and liabilities assumed. Dynegy’s allocation of the purchase price to specific assets and liabilities is based upon customary valuation procedures and techniques.
The following table summarizes the fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):
| Cash |
$ | 16 | ||
| Restricted cash and investments (including $37 million current) |
91 | |||
| Accounts receivable |
52 | |||
| Inventory |
37 | |||
| Assets from risk management activities (including $11 million current) |
37 | |||
| Prepaids and other current assets |
12 | |||
| Property, plant and equipment |
4,223 | |||
| Intangible assets (including $9 million current) |
224 | |||
| Goodwill |
486 | |||
| Unconsolidated investments |
83 | |||
| Other |
35 | |||
| Total assets acquired |
$ | 5,296 | ||
| Current liabilities and accrued liabilities |
$ | (92 | ) | |
| Liabilities from risk management activities (including $14 million current) |
(75 | ) | ||
| Long-term debt (including $32 million current) |
(1,898 | ) | ||
| Deferred income taxes |
(627 | ) | ||
| Other |
(96 | ) | ||
| Minority interest |
22 | |||
| Total liabilities and minority interest assumed |
$ | (2,766 | ) | |
| Net assets acquired |
$ | 2,530 | ||
During the fourth quarter 2007, Dynegy finalized and revised its purchase price allocation. The revision resulted in an increase in intangible assets acquired related to power purchase agreements associated with our interest in the Plum Point Project totaling approximately $192 million and reduced the excess of the fair value of the assets acquired and the liabilities assumed. Accordingly, in the fourth quarter 2007, Dynegy increased Intangible assets by approximately $192 million, Deferred income taxes by approximately $94 million, Other assets by approximately $10 million and decreased Goodwill by approximately $108 million.
As noted above, Dynegy recorded goodwill of approximately $486 million. Of the goodwill recorded, $81 million was assigned to the GEN-MW reporting unit, $308 million was assigned to the GEN-WE reporting unit and $97 million was assigned to the GEN-NE reporting unit.
Dynegy recorded net intangible assets of $185 million. This consisted of intangible assets of $192 million in GEN-MW and $32 million in GEN-WE offset by intangible liabilities of $4 million and $35 million, respectively, in GEN-NE and GEN-MW. Please read Note 14 Intangible Assets—LS Power for further discussion of the intangible assets.
F-27
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The intangible liability of $35 million in GEN-MW primarily related to a contract held by LSP Kendall Holding LLC, one of the entities transferred to Dynegy, and ultimately DHI, by the LS Contributing Entities. LSP Kendall Holding LLC was party to a power tolling agreement with another of our subsidiaries. This power tolling agreement had a fair value of approximately $31 million as of April 2, 2007, representing a liability from the perspective of LSP Kendall Holding LLC. Upon completion of the Merger, this power tolling agreement was effectively settled, which resulted in a second quarter 2007 gain equal to the fair value of this contract, in accordance with EITF Issue 04-01, “Accounting for Pre-existing Contractual Relationships Between the Parties to a Purchase Business Combination” (“EITF Issue 04-1”). We recorded a second quarter 2007 pre-tax gain of approximately $31 million, included as a reduction to cost of sales on the consolidated statements of operations.
The differences between the financial and tax bases of purchased intangibles and goodwill are not deductible for tax purposes. However, purchase accounting allows for the establishment of deferred tax liabilities on purchased intangibles (other than goodwill) that will be reflected as a tax benefit on our future consolidated statements of operations in proportion to and over the amortization period of the related intangible asset.
Dynegy’s results of operations include the results of the acquired entities for the period beginning April 2, 2007. The following table presents unaudited pro forma information for 2007, 2006 and 2005 as if the acquisition had occurred on January 1, 2007, 2006 or 2005, respectively:
| Twelve Months Ended December 31, 2007 |
Twelve Months Ended December 31, 2006 |
Twelve Months Ended December 31, 2005 |
|||||||||||||||||||
| Actual |
Pro Forma (Unaudited) |
Actual |
Pro Forma (Unaudited) |
Actual |
Pro Forma (Unaudited) |
||||||||||||||||
| (in millions, except per share amounts) | |||||||||||||||||||||
| Revenue |
$ | 3,103 | $ | 3,392 | $ | 1,770 | $ | 2,739 | $ | 2,017 | $ | 2,063 | |||||||||
| Income (loss) before cumulative effect of change in accounting principal |
264 | 216 | (334 | ) | (354 | ) | 95 | 4 | |||||||||||||
| Net income (loss) applicable to common stockholders |
264 | 216 | (342 | ) | (362 | ) | 68 | (23 | ) | ||||||||||||
| Basic earnings (loss) per share before cumulative effect of accounting change |
$ | 0.35 | $ | 0.29 | $ | (0.75 | ) | $ | (0.45 | ) | $ | 0.19 | $ | (0.02 | ) | ||||||
| Diluted earnings (loss) per share before cumulative effect of accounting change |
0.35 | 0.29 | (0.75 | ) | (0.45 | ) | 0.19 | (0.02 | ) | ||||||||||||
| Basic earnings (loss) per share |
0.35 | 0.29 | (0.75 | ) | (0.45 | ) | 0.18 | (0.03 | ) | ||||||||||||
| Diluted earnings (loss) per share |
0.35 | 0.29 | (0.75 | ) | (0.45 | ) | 0.18 | (0.03 | ) | ||||||||||||
These unaudited pro forma results, based on assumptions deemed appropriate by management, have been prepared for informational purposes only and are not necessarily indicative of Dynegy’s results if the Merger had occurred on January 1, 2007, 2006 and 2005 respectively, for the years ended December 31, 2007, 2006 and 2005. Pro forma adjustments to the results of operations include the effects on depreciation and amortization, interest expense, interest income and income taxes. The unaudited pro forma condensed consolidated financial statements reflect the Merger in accordance with SFAS No. 141 and SFAS No. 142.
The consummation of the Merger constituted a change in control as defined in our severance pay plans, as well as the various long-term incentive award grant agreements. As a result, all outstanding restricted stock and stock option awards previously granted to employees vested in full on April 2, 2007 upon the closing of the Merger. Specifically, the vesting of the restricted stock awards granted in 2005 and 2006 and the unvested tranches of stock option awards granted in those years were accelerated. Accordingly, we recorded a charge of approximately $6 million in 2007, included in general and administrative expense on our consolidated statement of operations.
F-28
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
LS Assets Contribution. In April 2007, in connection with the completion of the Merger, Dynegy contributed to Dynegy Illinois its interest in the Contributed Entities. Following such contribution, Dynegy Illinois contributed to DHI its interest in the Contributed Entities and, as a result, the Contributed Entities are subsidiaries of DHI. Accordingly, all of the entities acquired in the Merger are included within DHI with the exception of Dynegy’s 50 percent interests in DLS Power Holdings and DLS Power Development, which are directly owned by Dynegy.
DHI’s results of operations include the results of the acquired entities for the period beginning April 2, 2007. The following table presents unaudited pro forma information for 2007, 2006 and 2005, as if the acquisition and subsequent contribution had occurred on January 1, 2007, 2006 or 2005 respectively:
| Twelve Months Ended December 31, 2007 |
Twelve Months Ended December 31, 2006 |
Twelve Months Ended December 31, 2005 |
|||||||||||||||||||
| Actual |
Pro Forma (Unaudited) |
Actual |
Pro Forma (Unaudited) |
Actual |
Pro Forma (Unaudited) |
||||||||||||||||
| (in millions) | |||||||||||||||||||||
| Revenue |
$ | 3,103 | $ | 3,392 | $ | 1,770 | $ | 2,739 | $ | 2,017 | $ | 2,063 | |||||||||
| Net income (loss) |
324 | 279 | (308 | ) | (319 | ) | 81 | (4 | ) | ||||||||||||
These unaudited pro forma results, based on assumptions deemed appropriate by management, have been prepared for informational purposes only and are not necessarily indicative of DHI’s results if the Merger had occurred on January 1, 2007, 2006 and 2005, respectively, for the twelve months ended December 31, 2007, 2006 and 2005. Pro forma adjustments to the results of operations include the effects on depreciation and amortization, interest expense, interest income and income taxes. The unaudited pro forma condensed consolidated financial statements reflect the Merger in accordance with SFAS No. 141 and SFAS No. 142.
Sithe Energies Business Combination. On January 31, 2005, Dynegy acquired, and subsequently contributed to DHI, 100 percent of the outstanding common shares of ExRes SHC, Inc. (“ExRes”), the parent company of Sithe Energies, Inc. (“Sithe Energies”) and Sithe/Independence Power Partners, L.P. (“Independence”). The results of the operations of ExRes have been included in Dynegy’s consolidated financial statements since that date. Through this acquisition, Dynegy acquired 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”). Dynegy has not consolidated the entities that own these four natural gas-fired facilities and four hydroelectric generation facilities, in accordance with the provisions of FIN No. 46(R), “Consolidation of Variable Interest Entities an interpretation of ARB No. 51” (“FIN No. 46(R)”). Please read Note 12—Variable Interest Entities for additional discussion of these facilities. In addition to these power plants, Dynegy acquired the 740 MW firm capacity sales agreement between Independence and Con Edison, a subsidiary of Consolidated Edison, Inc. This agreement, which runs through 2014, will provide Dynegy with annual cash receipts of approximately $100 million, subject to the restrictions on distribution under Independence’s indebtedness. Revenue from this capacity obligation is largely fixed with a variable discount that varies each month based on the price of power at Pleasant Valley LMP. Please read Note 14—Intangible Assets—Sithe for further discussion of the acquired intangible assets. Independence holds power tolling, financial swap and other contracts with other Dynegy subsidiaries. Because of the acquisition, these contracts have become intercompany agreements, and their financial statement impact has been substantially eliminated. This transaction enabled us to address one of our outstanding power tolling arrangements and to expand our generation capacity in a market where we have an existing presence.
The aggregate purchase price was comprised of (i) $135 million cash, which was reduced by a purchase price adjustment of approximately $2 million; (ii) transaction costs of approximately $16 million, approximately
F-29
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
$3 million of which were paid in 2004; and (iii) the assumption of $919 million of face value project debt, which was recorded at its fair value of $797 million as of January 31, 2005. Please read Note 15—Debt—Sithe Senior Notes for additional information regarding the debt assumed.
The allocation of purchase price to specific assets and liabilities is based upon customary valuation procedures and techniques. The acquisition resulted in an excess of the fair value of assets acquired over cost of the acquisition. This excess was then allocated to property, plant and equipment and intangible assets acquired, including intangible assets arising from contracts with other Dynegy subsidiaries, on a pro-rata basis. The following table summarizes the fair values of the assets and liabilities acquired at the date of acquisition, January 31, 2005 (in millions):
| Other current assets |
$ | 88 | ||
| Restricted cash and investments |
132 | |||
| Property, plant and equipment |
353 | |||
| Assets from risk-management activities |
62 | |||
| Intangible assets |
657 | |||
| Other assets |
4 | |||
| Total assets acquired |
$ | 1,296 | ||
| Current liabilities |
$ | (98 | ) | |
| Deferred income taxes |
(193 | ) | ||
| Other long-term liabilities |
(59 | ) | ||
| Long-term debt |
(797 | ) | ||
| Total liabilities assumed |
$ | (1,147 | ) | |
| Net assets acquired |
$ | 149 | ||
Included in the assets acquired are restricted cash and investments of approximately $132 million. The restricted investments include Federal Home Loan Bank Bonds, U.S. Treasury Bonds, and high-grade short-term commercial paper. The restricted cash and investments are related to a sinking fund required by Independence’s debt instruments, including a major overhaul reserve, a debt service reserve, a principal payment reserve, an interest reserve and a project restoration reserve. Restrictions on the cash and investments are scheduled to be lifted at the end of the project financing term in 2014. Please read Note 15—Debt—Sithe Senior Notes for further discussion.
Sithe Assets Contribution. In April 2007, Dynegy Illinois contributed to DHI all of its interest in New York Holdings, together with its indirect interest in the subsidiaries of New York Holdings. New York Holdings, together with its wholly owned subsidiaries, owns the Sithe Assets. The Sithe Assets primarily consist of the Independence power generation facility. This contribution was accounted for as a transaction between entities under common control. As such, the assets and liabilities of New York Holdings 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 New York Holdings beginning January 31, 2005.
Rocky Road. On March 31, 2006, contemporaneous with our sale of our interest in WCP (Generation) Holdings LLC (“West Coast Power”), we completed our acquisition of NRG’s 50 percent ownership interest in Rocky Road Power, LLC (“Rocky Road”), the entity that owns the Rocky Road power plant, a 330-megawatt natural gas-fired peaking facility near Chicago (of which we already owned 50 percent), for proceeds of $165
F-30
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
million, net of cash acquired. As a result of the transaction, we became the primary beneficiary of the entity as provided under the guidance in FIN No. 46(R), and thus consolidated the assets and liabilities of the entity at March 31, 2006. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—West Coast Power and Note 11—Unconsolidated Investments for further discussion.
Note 4—Dispositions, Contract Terminations and Discontinued Operations
Dispositions and Contract Terminations
PPEA Holding Company LLC. On December 13, 2007, we sold a non-controlling ownership interest in PPEA to certain affiliates of John Hancock Life Insurance Company (“Hancock”) for approximately $82 million, which is net of non-recourse project debt. The non-controlling interest purchased by Hancock represents approximately 125 MW of generating capacity in the Plum Point power generation facility. Upon closing, we own a 37 percent interest in PPEA, representing an equivalent of approximately 140 MW, and continue in our role as administrative project manager. The sale met the requirements set forth in SFAS No. 66, “Accounting for Sales of Real Estate”. As such, we recognized a pre-tax gain totaling approximately $39 million ($24 million after-tax) in the fourth quarter 2007. The gain is included in Gain on sale of assets in our consolidated statements of operations.
Rockingham. Beginning in the second quarter 2006, the Rockingham power generation facility met the held for sale classification requirements of SFAS No. 144, and continued to meet the requirements through the closing of the sale on November 9, 2006. SFAS No. 144 requires that long-lived assets not be depreciated or amortized while they are classified as held for sale. As a result, we discontinued depreciation and amortization of the Rockingham power generation facility’s property, plant and equipment during the second quarter 2006. Depreciation and amortization expense related to the Rockingham power generation facility totaled $2 million and $6 million in the years ended December 31, 2006 and 2005, respectively. In addition, SFAS No. 144 requires a loss to be recognized if assets held for sale less liabilities held for sale are in excess of fair value less costs to sell. Accordingly, we recorded a pre-tax impairment of $9 million in the year ended December 31, 2006, which is included in Impairment and other charges in our consolidated statements of operations.
On November 9, 2006, we completed the sale to Duke Energy Carolinas, LLC (a subsidiary of Duke Energy) (“Duke Power”) of our Rockingham facility, a peaking facility in North Carolina, which was included in our GEN-WE reportable segment, for $194 million in cash. A portion of the proceeds from the sale were used to repay our borrowings under a $150 million Term Loan, with the remaining proceeds used as an additional source of liquidity. Please read Note 15—Debt—Fifth Amended and Restated Credit Facility for further discussion of the Term Loan.
West Coast Power. On March 31, 2006, contemporaneous with our purchase of Rocky Road, we completed the sale to NRG of our 50 percent ownership interest in West Coast Power, a joint venture between us and NRG which has ownership interests in the West Coast Power power plants in southern California totaling approximately 1,800 MW, for proceeds of approximately $165 million, net of cash acquired. We did not recognize a material gain or loss on the sale. Pursuant to our divestiture of West Coast Power, we no longer maintain a significant variable interest in the entity as provided by the guidance in FIN No. 46(R). Please read Note 3—Business Combinations and Acquisitions—Rocky Road.
Sterlington Contract Termination. In December 2005, we entered into an agreement to terminate the Sterlington long-term wholesale power tolling contract with Ouachita Power LLC (“Ouachita”), a joint venture
F-31
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
of GE Energy Financial Services and Cogentrix Energy, Inc. Under the terms of the agreement, we paid Ouachita approximately $370 million in March 2006 to eliminate approximately $449 million in capacity payment obligations through 2012 and avoid approximately $295 million in additional capacity payment obligations that would arise if Ouachita exercised its option to extend the contract through 2017. We recognized a pre-tax charge of approximately $364 million in 2005 related to this transaction.
GEN-WE Discontinued Operations
CoGen Lyondell. Beginning in the second quarter 2007, the CoGen Lyondell power generation facility met the held for sale classification requirements of SFAS No. 144, and continued to meet the requirements through the closing of the sale on August 1, 2007. SFAS No. 144 requires that long-lived assets not be depreciated or amortized while they are classified as held for sale. As a result, we discontinued depreciation and amortization of the CoGen Lyondell power generation facility’s property, plant and equipment during the second quarter 2007. Depreciation and amortization expense related to the CoGen Lyondell power generation facility totaled approximately $5 million, $11 million and $10 million in the years ended December 31, 2007, 2006 and 2005, respectively. Also pursuant to SFAS No. 144, we are reporting the results of CoGen Lyondell’s operations in discontinued operations for all periods presented.
On August 1, 2007, we completed our sale of the CoGen Lyondell power generation facility for approximately $470 million to EnergyCo, LLC (“EnergyCo”), 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. The gain includes the impact of allocating approximately $48 million of goodwill associated with the GEN-WE reporting unit to the CoGen Lyondell power generation facility. During the fourth quarter 2007, we reduced our allocation of goodwill to this transaction by $14 million due to revisions of our purchase price allocation in connection with the Merger. The amount of goodwill allocated to the CoGen Lyondell power generation facility was based on relative fair values of the CoGen Lyondell power generation facility and the portion of the GEN-WE reporting unit being retained.
The sale of the CoGen Lyondell power generation facility represented the sale of a significant portion of a reporting unit. As such, in accordance with SFAS No. 142, during the third quarter 2007, we tested the goodwill of the GEN-WE reporting unit for impairment. No impairment was indicated as a result of this test.
Calcasieu. Beginning in the first quarter 2007, the Calcasieu power generation facility met the held for sale classification requirements of SFAS No. 144 which requires that long-lived assets not be depreciated or amortized while they are classified as held for sale. As a result, we discontinued depreciation and amortization of the Calcasieu power generation facility’s property, plant and equipment during the first quarter 2007. Depreciation and amortization expense related to the Calcasieu power generation facility totaled approximately zero, $2 million and $2 million in the years ended December 31, 2007, 2006 and 2005, respectively. Also pursuant to SFAS No. 144, we are reporting the results of Calcasieu’s operations in discontinued operations for all periods presented.
On January 31, 2007, we entered into an agreement to sell our interest in the Calcasieu power generation facility to Entergy Gulf States, Inc. (“Entergy”) for approximately $57 million, subject to regulatory approval. The transaction is expected to close in early 2008. We recorded a pre-tax impairment of approximately $36 million in the year ended December 31, 2006, which was included in Income (loss) from discontinued operations on our consolidated statements of operations. Please read Note 5—Restructuring and Impairment Charges—Asset Impairments for further discussion.
F-32
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Other Discontinued Operations
Natural Gas Liquids. On October 31, 2005, we completed the sale of DMSLP, which comprised substantially all remaining operations of our NGL business, to Targa and two of its subsidiaries for $2,440 million in cash.
Pursuant to SFAS No. 144, we are reporting the results of NGL’s operations as a discontinued operation. Accordingly, the results of operations of our NGL business have been included in discontinued operations for all periods presented. EITF Issue 87-24, “Allocation of Interest to Discontinued Operations” (“EITF Issue 87-24”) requires that interest expense on debt that was required to be repaid upon the sale of DMSLP should be reclassified to discontinued operations. Therefore, interest expense on our former term loan and our former generation facility debt was allocated to discontinued operations, as the respective debt instruments were paid upon the sale of DMSLP. Such interest expense, inclusive of amortization of debt issuance costs, totaled $53 million for the year ended December 31, 2005.
Additionally, results from NGL’s operations include revenues and cost of sales arising from intersegment transactions, which ceased after the sale of DMSLP. NGL processed natural gas and sold this natural gas to CRM for resale to third parties. NGL also purchased natural gas from CRM and electricity from GEN. As the intersegment revenues and cost of sales included in NGL’s results were reclassified to discontinued operations, the effects of these intersegment transactions eliminated in consolidation, including the ultimate third-party settlement, previously recorded in other segments, were also reclassified to discontinued operations.
Other. We sold or liquidated some of our operations during 2003, including DGC (our communications business) and our U.K. CRM business, which have been accounted for as discontinued operations under SFAS No. 144. In 2007 and 2006, we recognized approximately $11 million and $21 million of pre-tax income related to favorable settlements of legacy receivables. In 2005, we recognized $3 million of pre-tax income primarily associated with U.K. CRM’s receipt of a third-party bankruptcy settlement, offset by foreign currency exchange losses.
The following table summarizes information related to Dynegy’s discontinued operations:
| GEN-WE |
CRM |
DGC |
NGL |
Total |
|||||||||||||||
| (in millions) | |||||||||||||||||||
| 2007 |
|||||||||||||||||||
| Revenues |
$ | 307 | $ | — | $ | — | $ | — | $ | 307 | |||||||||
| Income from operations before taxes |
1 | 15 | (1 | ) | — | 15 | |||||||||||||
| Income (loss) from operations after taxes |
1 | 15 | — | 11 | 27 | ||||||||||||||
| Gain on sale before taxes |
224 | — | — | — | 224 | ||||||||||||||
| Gain on sale after taxes |
121 | — | — | — | 121 | ||||||||||||||
| 2006 |
|||||||||||||||||||
| Revenues |
$ | 247 | $ | — | $ | — | $ | — | $ | 247 | |||||||||
| Income (loss) from operations before taxes |
(53 | ) | 23 | 1 | 6 | (23 | ) | ||||||||||||
| Income (loss) from operations after taxes |
(37 | ) | 19 | 1 | 4 | (13 | ) | ||||||||||||
| 2005 |
|||||||||||||||||||
| Revenues |
$ | 294 | $ | — | $ | — | $ | 4,125 | $ | 4,419 | |||||||||
| Income from operations before taxes |
(6 | ) | 6 | 163 | 163 | ||||||||||||||
| Income (loss) from operations after taxes |
(4 | ) | (1 | ) | 2 | 223 | 220 | ||||||||||||
| Gain on sale before taxes |
— | — | — | 1,087 | 1,087 | ||||||||||||||
| Gain on sale after taxes |
— | — | — | 675 | 675 | ||||||||||||||
F-33
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following table summarizes information related to DHI’s discontinued operations:
| GEN-WE |
CRM |
NGL |
Total |
||||||||||||
| (in millions) | |||||||||||||||
| 2007 |
|||||||||||||||
| Revenues |
$ | 307 | $ | — | $ | — | $ | 307 | |||||||
| Income from operations before taxes |
1 | 15 | — | 16 | |||||||||||
| Income (loss) from operations after taxes |
1 | 15 | 11 | 27 | |||||||||||
| Gain on sale before taxes |
224 | — | — | 224 | |||||||||||
| Gain on sale after taxes |
121 | — | — | 121 | |||||||||||
| 2006 |
|||||||||||||||
| Revenues |
$ | 247 | $ | — | $ | — | $ | 247 | |||||||
| Income (loss) from operations before taxes |
(53 | ) | 23 | 6 | (24 | ) | |||||||||
| Income (loss) from operations after taxes |
(37 | ) | 21 | 4 | (12 | ) | |||||||||
| 2005 |
|||||||||||||||
| Revenues |
$ | 294 | $ | — | $ | 4,125 | $ | 4,419 | |||||||
| Income from operations before taxes |
(6 | ) | 6 | 163 | 163 | ||||||||||
| Income (loss) from operations after taxes |
(4 | ) | (1 | ) | 137 | 132 | |||||||||
| Gain on sale before taxes |
— | — | 1,087 | 1,087 | |||||||||||
| Gain on sale after taxes |
— | — | 681 | 681 | |||||||||||
Note 5—Restructuring and Impairment Charges
Asset Impairments. At September 30, 2006, we tested the Bluegrass generation facility for impairment based on FERC’s recent approval and Louisville Gas and Electric’s (“LG&E”) completion of various compliance steps to allow it to withdraw its transmission facilities from the MISO as of September 1, 2006. The Bluegrass facility has historically sold power into the MISO market through transmission provided by LG&E. This change limits our ability or increases the cost to deliver power to the MISO market. After testing, we recorded a pre-tax impairment charge of $96 million ($61 million after-tax) in the GEN-MW segment. This charge is included in Impairment and other charges in our consolidated statements of operations. We determined the fair value of the facility using the expected present value technique.
At December 31, 2006, we determined that it was more likely than not that certain assets would be sold prior to the end of their previously estimated useful lives. Therefore, impairment analyses were performed and we recorded a total pre-tax impairment charge of $50 million ($32 million after tax). Of this charge, $36 million relates to the Calcasieu facility and is recorded in the GEN-WE segment and is included in Income (loss) from discontinued operations on our consolidated statements of operations. The remaining $14 million relates to the Bluegrass facility and is recorded in the GEN-MW segment. This charge is included in Impairment and other charges in our consolidated statements of operations. We determined the fair value of the Bluegrass facility using the expected present value technique. We determined the fair value of the Calcasieu facility based on the purchase price in the sales agreement.
In 2006, we recorded a $9 million pre-tax impairment of our investment in Nevada Cogeneration Associates #2 (“Black Mountain”). Please read Note 11—Unconsolidated Investments for further discussion.
In 2005, we recorded $13 million, $10 million and $4 million in pre-tax impairments of our investments in Black Mountain, West Coast Power and Panama, respectively. Please read Note 11—Unconsolidated Investments for further discussion. Also in 2005, we recorded in GEN-MW an impairment of an unused turbine
F-34
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
totaling $29 million. We determined the fair value of the turbine based on market prices of similar assets available for sale. Also in 2005, we recorded severance and restructuring charges totaling $11 million. Please read “2005 Restructuring” below for further information. Finally, in connection with our sale of DMSLP, included in discontinued operations were charges of $3 million and $2 million for cancellation fees and operating leases, respectively.
2005 Restructuring. In December 2005, in order to better align our corporate cost structure with a single line of business and as part of a comprehensive effort to reduce on-going operating expenses, we implemented a restructuring plan (the “2005 Restructuring Plan”). The 2005 Restructuring Plan resulted in a reduction of approximately 40 positions and was complete by June 30, 2006. We recognized a pre-tax charge of $11 million in the fourth quarter 2005. We recognized approximately $2 million of charges in the year ended December 31, 2006, when transitional services were completed by certain affected employees. These charges related entirely to severance costs.
2002 Restructuring. In October 2002, we announced a restructuring plan (the “2002 Restructuring Plan”) designed to improve operational efficiencies and performance across our lines of business. The following is a schedule of 2007, 2006 and 2005 activity for the 2002 Restructuring Plan liabilities recorded associated with the severance, cancellation fees and operating leases:
| Severance |
Cancellation Fees and Operating Leases |
Total |
||||||||||
| (in millions) | ||||||||||||
| Balance at December 31, 2004 |
$ | 3 | $ | 25 | $ | 28 | ||||||
| 2005 cash payments |
— | (9 | ) | (9 | ) | |||||||
| Balance at December 31, 2005 |
3 | 16 | 19 | |||||||||
| 2006 adjustments to liability |
— | (1 | ) | (1 | ) | |||||||
| 2006 cash payments |
— | (8 | ) | (8 | ) | |||||||
| Balance at December 31, 2006 |
$ | 3 | $ | 7 | $ | 10 | ||||||
| 2007 adjustments to liability |
— | — | — | |||||||||
| 2007 cash payments |
(3 | ) | (7 | ) | (10 | ) | ||||||
| Balance at December 31, 2007 |
$ | — | $ | — | $ | — | ||||||
Note 6—Risk Management Activities and Financial Instruments
Our operations are impacted by several factors, some of which may not be mitigated by risk management methods. These risks include, but are not limited to, commodity price, interest rate and foreign exchange rate fluctuations, weather patterns, counterparty credit risks, changes in competition, operational risks, environmental risks and changes in regulations.
We define market risk as changes to our earnings and cash flow resulting from changes in market conditions, including changes in commodity prices, interest rates and currency rates as well as the impact of volatility and market liquidity on such prices. We seek to manage market risk through diversification, controlling position sizes and executing hedging strategies.
Accounting for Derivative Instruments and Hedging Activities
We follow the accounting and disclosure requirements of SFAS No. 133, as amended. Under SFAS No. 133, all derivative instruments are recognized in the balance sheet at their fair values and changes in fair
F-35
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
value are recognized immediately in earnings, unless such instruments qualify, and are designated, as hedges of future cash flows, fair values or net investments in foreign operations or qualify, and are designated, as normal purchases and sales.
Cash Flow Hedges. We enter into financial derivative instruments that qualify, and that we may elect to designate, as cash flow hedges. Interest rate swaps have been used to convert floating interest rate obligations to fixed interest rate obligations. In the second quarter 2007, PPEA entered into three interest rate swap agreements with an initial aggregate notional amount of approximately $184 million. These interest rate swap agreements convert certain of Plum Point’s floating rate debt exposure (exclusive of the Tax Exempt Bonds) to a fixed interest rate of approximately 5.3 percent. These interest rate swap agreements expire in June 2040. During the second quarter 2007, we recorded $27 million of mark-to-market income related to these interest rate swap agreements as an offset to interest expense. Effective July 1, 2007, we designated these agreements as cash flow hedges. Therefore, the effective portion of the changes in value after that date are reflected in Accumulated other comprehensive income (loss), and subsequently reclassified to interest expense contemporaneously with the related accruals of interest expense, or depreciation expense in the event the interest was capitalized, in either case to the extent of hedge effectiveness.
Instruments related to our GEN business, which are entered into for purposes of hedging future fuel requirements and sales commitments and securing commodity prices we consider favorable under the circumstances, have also historically been designated as cash flow hedges. Beginning on April 2, 2007, we chose to cease designating such instruments related to our GEN business as cash flow hedges, and thus apply mark-to-market accounting treatment prospectively. Accordingly, as values fluctuate from period to period due to market price volatility, value changes are reflected in our consolidated statements of operations. Pursuant to EITF Issue 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 02-3”), all gains and losses on third party energy trading contracts, whether realized or unrealized, are presented net in our consolidated statements of operations. The balance in Accumulated other comprehensive income (loss) at April 2, 2007 related to these instruments will be reclassified to future earnings contemporaneously with the related purchases of fuel and sales of electricity. As of December 31, 2007, this amount totaled $18 million pre-tax.
Any ineffective portion of a cash flow hedge is reported immediately as a component of income in the consolidated statements of operations. Ineffectiveness associated with cash flow hedges of commodity transactions and interest rate swaps is included in revenues and interest expense, respectively. During the years ended December 31, 2007, 2006 and 2005, we recorded $9 million, $7 million and $3 million of income, respectively, related to ineffectiveness from changes in fair value of hedge positions. No amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows in any of the periods.
During the years ended December 31, 2007, 2006 and 2005, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.
The balance in cash flow hedging activities, net at December 31, 2007 is expected to be reclassified to future earnings when the hedged transaction occurs. Of this amount, after-tax gains of approximately $11 million are currently estimated to be reclassified into earnings in 2008. The actual amounts that will be reclassified to earnings over this period and beyond could vary materially from this estimated amount as a result of changes in market prices, hedging strategies, the probability of forecasted transactions occurring and other factors.
F-36
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Fair Value Hedges. We also enter into derivative instruments that qualify, and that we designate, as fair value hedges. We use interest rate swaps to convert a portion of our non-prepayable fixed-rate debt into floating-rate debt. The maximum length of time for which we have hedged our exposure for fair value hedges is through 2012. During the years ended December 31, 2007, 2006 and 2005, there was no ineffectiveness from changes in the fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. During each of the years ended December 31, 2007, 2006 and 2005, there were no gains or losses related to the recognition of firm commitments that no longer qualified as fair value hedges.
In December 2007, we terminated three of our fair value hedges, which had been used to convert $500 million of fixed rate debt into floating rate debt. In connection with this termination, we received a payment of less than $1 million. We deferred termination gains of approximately $1 million which will be amortized into earnings over the remaining term of the underlying debt obligations, which will occur in 2011 and 2012.
Fair Value of Financial Instruments. The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, “Disclosures About Fair Value of Financial Instruments”. We have determined the estimated fair-value amounts using available market information and selected valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies could have a material effect on the estimated fair-value amounts.
The carrying values of current financial assets and liabilities approximate fair values due to the short-term maturities of these instruments. The carrying amounts and fair values of debt are included in Note 15—Debt and the carrying amounts and fair values of our NYMEX securities are included in Note 11—Unconsolidated Investments. The carrying amounts and fair values of our other financial instruments were:
| December 31, |
||||||||||||||||
| 2007 |
2006 |
|||||||||||||||
| Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
|||||||||||||
| (in millions) | ||||||||||||||||
| Cash flow hedge interest rate swap |
$ | (34 | ) | $ | (34 | ) | $ | — | $ | — | ||||||
| Fair value hedge interest rate swap |
2 | 2 | (19 | ) | (19 | ) | ||||||||||
| Interest rate risk-management contracts |
(2 | ) | (2 | ) | (1 | ) | (1 | ) | ||||||||
| Commodity cash flow hedge contracts |
— | — | (114 | ) | (114 | ) | ||||||||||
| Commodity risk-management contracts |
(66 | ) | (66 | ) | 14 | 14 | ||||||||||
Concentration of Credit Risk. We sell our energy products and services to customers in the electric and natural gas distribution industries and to entities engaged in industrial and petrochemical businesses. These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, because the customer base may be similarly affected by changes in economic, industry, weather or other conditions.
At December 31, 2007, our credit exposure as it relates to the mark-to-market portion of our risk management portfolio totaled $298 million. To reduce our credit exposure, we execute agreements that permit us to offset receivables, payables and mark-to-market exposure. We attempt to further reduce credit risk with certain counterparties by obtaining third party guarantees or collateral as well as the right of termination in the event of default.
F-37
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Our Credit Department establishes our counterparty credit limits. Our industry typically operates under negotiated credit lines for physical delivery and financial contracts. Our credit risk system provides current credit exposure to counterparties on a daily basis.
We enter into master netting agreements both to mitigate credit exposure and to reduce collateral requirements. In general, the agreements include our risk management subsidiaries and allow the aggregation of credit exposure, margin and set-off. As a result, we decrease a potential credit loss arising from a counterparty default.
We include cash collateral deposited with counterparties in Prepayments and other current assets and Other long-term assets on our consolidated balance sheets. We include cash collateral due to counterparties in Accrued liabilities and other current liabilities on our consolidated balance sheets.
Note 7—Accumulated Other Comprehensive Income (Loss)
Accumulated other comprehensive income (loss), net of tax (except foreign currency translation adjustment), is included in Dynegy’s stockholders’ equity and DHI’s stockholder’s equity on the consolidated balance sheets, respectively, as follows:
| December 31, |
||||||||
| 2007 |
2006 |
|||||||
| (in millions) | ||||||||
| Cash flow hedging activities, net |
$ | (39 | ) | $ | 76 | |||
| Foreign currency translation adjustment |
27 | 23 | ||||||
| Unrecognized prior service cost and actuarial loss |
(25 | ) | (43 | ) | ||||
| Available for sale securities |
12 | 11 | ||||||
| Accumulated other comprehensive income (loss), net of tax |
$ | (25 | ) | $ | 67 | |||
F-38
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Note 8—Cash Flow Information
Following are Dynegy’s supplemental disclosures of cash flow and non-cash investing and financing information:
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| (in millions) | ||||||||||||
| Interest paid (net of amount capitalized) |
$ | 393 | $ | 405 | $ | 408 | ||||||
| Taxes paid, net |
$ | 48 | $ | 9 | $ | 45 | ||||||
| Detail of businesses acquired: |
||||||||||||
| Current assets and other |
$ | 174 | $ | 14 | $ | 217 | ||||||
| Fair value of non-current assets |
5,122 | 13 | 1,076 | |||||||||
| Liabilities assumed, including deferred taxes |
(2,766 | ) | 18 | (1,147 | ) | |||||||
| Non-cash consideration (1) |
(2,378 | ) | — | — | ||||||||
| Cash balance acquired |
(16 | ) | (5 | ) | (26 | ) | ||||||
| Cash paid, net of cash acquired (2) |
$ | 136 | $ | 40 | $ | 120 | ||||||
| Other non-cash investing and financing activity: |
||||||||||||
| Non-cash construction expenditures (3) |
$ | 13 | $ | — | $ | — | ||||||
| Conversion of Convertible Subordinated Debentures due 2023 (Note 15) (4) |
— | 225 | — | |||||||||
| Sithe Subordinated Debt exchange, net |
— | 122 | — | |||||||||
| Addition of a capital lease (6) |
— | 6 | — | |||||||||
| Marketable securities (7) |
— | 18 | — | |||||||||
| (1) | Includes (i) 340 million shares of the Class B common stock of Dynegy valued at $5.98 per share, (ii) a promissory note in the aggregate principal amount of $275 million, and (iii) an additional $70 million of the Griffith Debt. Please read Note 3—Business Combinations and Acquisitions—LS Power Business Combination for further information. |
| (2) | Includes transaction costs associated with the Merger of approximately $44 million and $8 million for the years ended December 31, 2007 and 2006, respectively. |
| (3) | For the year ended December 31, 2007, we had non-cash construction expenditures of approximately $13 million. These expenditures related primarily to our interest in the Plum Point power generation facility. Please read Note 12—Variable Interest Entities—PPEA Holding Company LLC for further information. |
| (4) | In May 2006, Dynegy converted all $225 million of its outstanding 4.75 percent Convertible Subordinated Debentures due 2023 into shares of its Class A common stock (the “Convertible Debenture Exchange”). In this transaction, Dynegy issued an aggregate of 54,598,369 shares of our Class A common stock and paid the debenture holders an aggregate of approximately $47 million in premiums and accrued and unpaid interest using cash on hand. Please read Note 15—Debt—Convertible Subordinated Debentures due 2023 for further information. |
| (5) | In July 2006, we executed an exchange of approximately $419 million principal amount of the subordinated debt of Independence, together with all claims for accrued and unpaid interest thereon, for approximately $297 million principal amount of our 8.375 percent Senior Unsecured Notes due 2016. Please read Note 15—Debt—Sithe Senior Notes for further information. |
| (6) | 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 ten-year term of the lease. |
| (7) | In November 2006, the New York Mercantile Exchange completed its initial public offering. As a result, we received ninety thousand shares due to our two membership seats. |
F-39
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Following are DHI’s supplemental disclosures of cash flow and non-cash investing and financing information:
| Year Ended December 31, | ||||||||||
| 2007 |
2006 |
2005 | ||||||||
| (in millions) | ||||||||||
| Interest paid (net of amount capitalized) |
$ | 393 | $ | 402 | $ | 397 | ||||
| Taxes paid, net |
$ | 35 | $ | — | $ | 38 | ||||
| Detail of businesses acquired: |
||||||||||
| Current assets and other |
$ | — | $ | 14 | $ | — | ||||
| Fair value of non-current assets |
— | 13 | — | |||||||
| Liabilities assumed, including deferred taxes |
— | 18 | — | |||||||
| Non-cash consideration |
— | — | — | |||||||
| Cash balance acquired |
— | (5 | ) | — | ||||||
| Cash paid, net of cash acquired |
$ | — | $ | 40 | — | |||||
| Other non-cash investing and financing activity: |
||||||||||
| Non-cash construction expenditures (1) |
$ | 13 | $ | — | $ | — | ||||
| Contribution of the Contributed Entities to DHI (2) |
2,467 | — | — | |||||||
| Contribution of Sithe from Dynegy to DHI (3) |
— | — | 149 | |||||||
| Contribution of Sandy Creek from Dynegy to DHI (4) |
16 | — | — | |||||||
| Sithe Subordinated Debt exchange, net (Note 15) (5) |
— | 122 | — | |||||||
| Addition of a capital lease (6) |
— | 6 | — | |||||||
| Marketable securities (7) |
— | 18 | — | |||||||
| (1) | For the year ended December 31, 2007, we had non-cash construction expenditures of approximately $13 million. These expenditures related primarily to our interest in the Plum Point power generation facility. Please read Note 12—Variable Interest Entities—PPEA Holding Company LLC for further information. |
| (2) | In April 2007, Dynegy contributed to DHI its interest in the Contributed Entities. This contribution was accounted for as a transaction between entities under common control in a manner similar to a pooling of interests whereby the assets and liabilities were transfer at historical cost. Please read Note 3—Business Combinations and Acquisitions—LS Assets Contribution for further information. |
| (3) | In April 2007, Dynegy contributed to DHI its interest in New York Holdings. This contribution was accounted for as a transaction between entities under common control in a manner similar to a pooling of interests whereby the assets and liabilities were transferred at historical cost. Please read Note 3—Business Combinations and Acquisitions—Sithe Assets Contribution for further information. |
| (4) | In August 2007, Dynegy contributed to DHI its interest in SCH. This contribution was accounted for as a transaction between entities under common control in a manner similar to a pooling of interests whereby the assets and liabilities were transferred at historical cost. Please read Note 12—Variable Interest Entities—Sandy Creek for further information. |
| (5) | In July 2006, DHI executed an exchange of approximately $419 million principal amount of the subordinated debt of Independence, together with all claims for accrued and unpaid interest thereon, for approximately $297 million principal amount of DHI’s 8.375 percent Senior Unsecured Notes due 2016. Please read Note 15—Debt—Sithe Senior Notes for further information. |
| (6) | 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 ten-year term of the lease. |
| (7) | In November 2006, the New York Mercantile Exchange completed its initial public offering. As a result, we received ninety thousand shares due to our two membership seats. |
F-40
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Note 9—Inventory
A summary of our inventories is as follows:
| December 31, | ||||||
| 2007 |
2006 | |||||
| (in millions) | ||||||
| Materials and supplies |
$ | 72 | $ | 90 | ||
| Coal |
74 | 56 | ||||
| Fuel oil |
40 | 32 | ||||
| Emissions allowances |
11 | 15 | ||||
| Natural gas storage |
2 | 1 | ||||
| $ | 199 | $ | 194 | |||
Note 10—Property, Plant and Equipment
A summary of our property, plant and equipment is as follows:
| December 31, |
||||||||
| 2007 |
2006 |
|||||||
| (in millions) | ||||||||
| Generation assets: |
||||||||
| GEN—MW |
$ | 6,642 | $ | 5,070 | ||||
| GEN—WE |
2,393 | 569 | ||||||
| GEN—NE |
1,464 | 625 | ||||||
| IT systems and other |
190 | 209 | ||||||
| 10,689 | 6,473 | |||||||
| Accumulated depreciation |
(1,672 | ) | (1,522 | ) | ||||
| $ | 9,017 | $ | 4,951 | |||||
Interest capitalized related to costs of development projects in process totaled $15 million, $3 million and $3 million for the years ended December 31, 2007, 2006 and 2005, respectively.
Note 11—Unconsolidated Investments
Equity Method Investments. Our unconsolidated investments consist primarily of investments in affiliates that we do not control, but where we have significant influence over operations. Our principal equity method investments consist of entities that develop and construct generation assets. We entered into these ventures principally to share risk and leverage existing commercial relationships. These ventures maintain independent capital structures and have financed their operations either on a non-recourse basis to us or through their ongoing commercial activities.
F-41
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
A summary of our unconsolidated investments in equity method investees is as follows:
| December 31, | ||||||
| 2007 |
2006 | |||||
| (in millions) | ||||||
| Equity affiliates: |
||||||
| Sandy Creek Holdings LLC |
$ | 18 | $ | — | ||
| Black Mountain |
— | — | ||||
| Total unconsolidated investments—DHI |
18 | — | ||||
| DLS Power Holdings and DLS Power Development |
61 | — | ||||
| Total unconsolidated investments—Dynegy |
$ | 79 | $ | — | ||
Cash distributions received from our equity investments during 2007, 2006 and 2005 were $10 million, zero and $80 million, respectively. Undistributed earnings from our equity investments included in accumulated deficit at December 31, 2007 and 2006 totaled $16 million and zero, respectively.
Equity investments at December 31, 2007 include a 50 percent ownership interest in SCH, which owns all of Sandy Creek Energy Associates LP (“SCEA”). SCEA owns a 75 percent interest in the Sandy Creek Project, which is a proposed 898 MW facility to be located in McLennan County, Texas. Please read Note 12—Variable Interest Entities—Sandy Creek for further information.
Equity investments at December 31, 2007 and 2006 include a 50 percent ownership interest in Black Mountain, an 85 MW power generation facility in Las Vegas, Nevada that owns fossil fuel electric generation facilities. In 2007 and 2006, we recorded impairment charges of $7 million and $9 million, respectively, related to our 50 percent interest in Black Mountain. These charges are the result of declines in value of the investment caused by an increase in the 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. Please read Note 19—Commitments and Contingencies—Legal Proceedings—Nevada Power Arbitration for further information.
Dynegy’s equity investments at December 31, 2007 also include a 50 percent ownership interest in DLS Power Holdings and DLS Power Development LLC. The purpose of DLS Power Development is to provide services to DLS Power Holdings and the project subsidiaries related to power project development and to evaluate and pursue potential new development projects. Please read Note 12—Variable Interest Entities—DLS Power Holdings and DLS Power Development for further information.
Marketable Securities. In November 2006, the New York Mercantile Exchange (“NYMEX”) completed its initial public offering. At the time, we had two membership seats on the NYMEX, and therefore we received ninety thousand NYMEX shares per membership seat. During August 2007, we sold approximately thirty thousand shares for approximately $4 million, and we recognized a gain of $4 million. Our investment in the NYMEX shares was valued at approximately $21 million and $18 million at December 31, 2007 and 2006, respectively.
Note 12—Variable Interest Entities
Hydroelectric Generation Facilities. On January 31, 2005, Dynegy completed the acquisition of ExRes. As further discussed in Note 3—Business Combinations and Acquisitions—Sithe Assets Contribution, on April 2, 2007, Dynegy contributed its interest in the Sithe Assets to DHI. ExRes also owns through its subsidiaries four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. The entities owning these facilities meet the definition of VIEs. In accordance with the purchase agreement,
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DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Exelon Corporation (“Exelon”) has the sole and exclusive right to direct our efforts to decommission, sell, bankrupt, or otherwise dispose of the hydroelectric facilities owned through the VIE entities. Exelon is obligated to reimburse ExRes for all costs, liabilities, and obligations of the entities owning these hydroelectric generation facilities, and to indemnify ExRes with respect to the past and present assets and operations of the entities. As a result, we are not the primary beneficiary of the entities and have not consolidated them in accordance with the provisions of FIN No. 46(R).
With regard to the four natural gas-fired merchant facilities located in New York, Dynegy had the option to elect to decommission any or all of these facilities within a 180-day period after the January 31, 2005 closing date. Prior to expiration of the option period, which ended on July 30, 2005, Dynegy elected to decommission all four of the natural gas-fired merchant facilities owned by ExRes. Under the terms of the purchase agreement, Exelon was permitted to direct the decommissioning, sale or other disposal of the facilities. Further, Exelon is obligated to indemnify Dynegy with respect to all operations prior to February 1, 2005 and subsequent to Dynegy’s election to decommission or sell the facilities. Exelon also must provide written consent for any payments or actions outside the ordinary course of operations. On June 1 and August 4, 2005, Dynegy entered into agreements, as directed by Exelon, to sell Dynegy’s ownership and operating interests in the four natural gas-fired power generation peaking facilities to Alliance Energy Group LLC. The transactions, which were approved by FERC and the New York Public Service Commission, closed on October 31, 2005 and had no impact on Dynegy’s consolidated financial statements, as Exelon received the proceeds from the sale. As a result of the rights retained by Exelon with respect to these facilities, Dynegy is not the primary beneficiary of these VIEs, and has not consolidated them in accordance with the provisions of FIN No. 46(R). Please read Note 3—Business Combinations and Acquisitions—Sithe Energies Business Combination for further discussion regarding this acquisition.
These hydroelectric generation facilities have commitments and obligations that are off-balance sheet with respect to Dynegy arising under operating leases for equipment and long-term power purchase agreements with local utilities. At December 31, 2007, the equipment leases have remaining terms from two to twenty-five years and involve future lease payments of $149 million over the terms of the leases. Additionally, each of these facilities is party to a long-term power purchase agreement with a local utility. Under the terms of each of these agreements, a project tracking account (the “Tracking Account”) was established to quantify the difference between (i) the facility’s fixed price revenues under the power purchase agreement and (ii) the respective utility’s Public Utility Commission approved avoided costs associated with those power purchases plus accumulated interest on the balance. Each power purchase agreement calls for the hydroelectric facility to return to the utility the balance in the Tracking Account before the end of the facility’s life through decreased pricing under the respective power purchase agreement. All four of the four hydroelectric facilities are currently in the Tracking Account repayment period of the contract, whereby balances are repaid through decreased pricing. This pricing cannot be decreased below a level sufficient to allow the facilities to recover their operating costs, exclusive of lease or interest costs. The aggregate balance of the Tracking Accounts as December 31, 2007 was approximately $347 million, and the obligations with respect to each Tracking Account are secured by the assets of the respective facility. The decreased pricing necessary to reduce the Tracking Accounts may cause the facilities to operate at a net cash deficit. As discussed above, the obligations of the four hydroelectric facilities are non-recourse to us. Under the terms of the stock purchase agreement with Exelon, we are indemnified for any net cash outflow arising from ownership of these facilities.
PPEA Holding Company LLC. On April 2, 2007, in connection with the completion of the Merger, we acquired a 70 percent interest in PPEA, which owns and operates Plum Point Energy Associates, LLC (“Plum Point”). Plum Point is constructing a 665 MW coal-fired power generation facility (the “Plum Point Project”), located in Mississippi County, Arkansas, in which it owns an approximate 57 percent undivided interest. Plum Point is the Borrower under a $700 million term loan facility, a $17 million revolving credit facility, and a $102
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DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
million letter of credit facility securing $100 million of Tax Exempt Bonds. See Note 15—Debt—Plum Point Tax Exempt Bonds for discussion. The Plum Point Project indebtedness is an obligation of Plum Point. The payment obligations of Plum Point in respect of the Bank Loan, the Revolver, and the LC Facility are unconditionally and irrevocably guaranteed by Ambac Assurance Corporation, an independent third party insurance company. The credit facilities and insurance policy are secured by a security interest in all of Plum Point’s assets, contract rights and Plum Point’s undivided tenancy in common interest in the Plum Point Project and PPEA’s interest in Plum Point. These assets consist primarily of $309 million of plant construction in progress at December 31, 2007. There are no guarantees of the indebtedness by any parties, and Plum Point’s creditors have no recourse against our general credit. Currently, we have posted a $15 million letter of credit to support our equity contribution to the Plum Point Project and Hancock and EIF, respectively, have also posted a $15 million and a $16 million letter of credit to support their equity contributions to the Plum Point Project. See Note 15—Debt—Plum Point Credit Agreement Facility for discussion of Plum Point’s borrowings. PPEA meets the definition of a VIE, and, at the acquisition date, we determined we were the primary beneficiary of this entity.
On December 13, 2007, we sold a portion of our interest in PPEA for approximately $82 million, reducing our ownership interest to 37 percent. After the sale, we are still considered the primary beneficiary because we will continue to absorb a majority of the expected losses. As such, we continue to consolidate PPEA in accordance with the provisions of FIN No. 46(R).
DLS Power Holdings and DLS Power Development. As discussed in Note 3—Business Combinations and Acquisitions—LS Power Business Combination, on April 2, 2007, in connection with Merger, Dynegy acquired a 50 percent interest in DLS Power Holdings and DLS Power Development. The purpose of DLS Power Development is to provide services to DLS Power Holdings and the project subsidiaries related to power project development and to evaluate and pursue potential new development projects. DLS Power Holdings and DLS Power Development meet the definition of VIEs, as they will require additional subordinated financial support from their owners to conduct normal on-going operations. However, Dynegy is not the primary beneficiary of the entities and, in accordance with the provisions of FIN No. 46(R), has not consolidated them. Dynegy accounts for its investments in DLS Power Holdings and DLS Power Development as equity method investments pursuant to APB 18, “The Equity Method of Accounting for Investments in Common Stock”. Dynegy’s maximum exposure to economic loss from this VIE is limited to $61 million, which represents its equity investment in these entities at December 31, 2007.
A substantial portion of the purchase price allocated to these investments, and the equity investment at December 31, 2007, represents Dynegy’s estimate of its proportionate share of the fair value of the underlying intangible assets associated with each of the development projects in excess of the equity of the underlying assets. Depending on the outcome of each development project, Dynegy could be required to record an impairment to its investment related to these intangible assets.
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 SCH, which owned all of SCEA. SCEA owns the Sandy Creek Project, which is a proposed 898 MW facility to be located in McLennan County, Texas. In August 2007, SCH became a stand-alone entity separate from DLS Power Holdings, 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. As a result, SCEA currently owns a 75 percent interest in the Sandy Creek Project.
Dynegy Sandy Creek Holdings, LLC (the “Dynegy Member”), an indirectly wholly owned subsidiary of Dynegy, and LSP Sandy Creek Member, LLC (the “LSP Member”) each own a 50 percent interest in SCH. In addition, Sandy Creek Services, LLC (“SC Services”) was formed to provide services to SCH. Dynegy Power Services and LSP Sandy Creek Services LLC each own a 50 percent interest in SC Services.
Dynegy’s 50 percent interest in SCH, as well as a related intangible asset of approximately $23 million, were subsequently contributed to a wholly owned subsidiary of DHI. This contribution was accounted for as a transaction between entities under common control. As such, DHI’s investment in SCH, as well as the related
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DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
intangible asset, were recorded by DHI at Dynegy’s historical cost on the acquisition date. DHI’s investment in SCH is included in GEN-WE.
SCH and SC Services both meet the definition of a VIE, as they will require additional subordinated financial support to conduct their normal on-going operations. However, we are not the primary beneficiary of the entities, and, in accordance with FIN No. 46(R), do not consolidate them. We account for our investments in SCH and SC Services as equity method investments pursuant to APB 18. We believe that our maximum exposure to economic loss from these VIEs is limited to $341 million, which represents our $18 million equity investment in these entities at December 31, 2007 and restricted cash of $323 million that has been posted in support of our funding commitment.
The financing agreements consist of a $200 million term loan and $800 million in construction loans with SCEA as borrower. The SCEA debt is secured by a pledge of SCEA’s assets and contract rights and SCEA’s undivided tenancy in common interest in the Sandy Creek Project as well as a pledge of the equity of SCEA by its direct parents.
In connection with the SCEA term and construction financing described above, SCH entered into arrangements to make capital contributions to SCEA of up to $200 million to fund project costs after the loans under the SCEA financing have been utilized and otherwise upon certain conditions. SCH’s obligation to make such contributions is supported by a credit agreement with the Dynegy Member and LSP Sandy Creek Holdings, LLC, as lenders, and SCH, as borrower. The lenders provide for commitments of $200 million in loans to SCH. This SCH debt is secured by a pledge of SCH’s indirect ownership interests in SCEA. The Dynegy Member’s 50 percent share of the SCH credit agreement is supported by a letter of credit in the amount of $100 million issued under a stand-alone letter of credit facility between the Dynegy Member and ABN AMRO Bank, N.V. Such letter of credit may be drawn upon by the SCEA lenders if certain conditions are met.
The Dynegy Member and the LS Member each also agreed to make capital contributions of $223 million to fund project costs after the SCEA and SCH loans have been utilized and otherwise upon the occurrence of certain events and milestone dates. The Dynegy Member’s obligation to make such contributions is supported by a letter of credit in the amount of $223 million issued under a stand-alone letter of credit facility between the Dynegy Member and ABN AMRO Bank, N.V. Such letter of credit may be drawn upon by the SCEA lenders if certain conditions are met.
Upon the close of the financing agreements discussed above, SCEA sold a 25 percent undivided interest in the Sandy Creek Project for approximately $30 million plus reimbursement for a related portion of accumulated construction costs and the obligation to assume a proportionate share of future construction costs. During 2007, we recognized our share of the gain on the sale, which approximated $10 million, in Earnings from unconsolidated investments on our consolidated statements of operations. During 2007, SCEA received $24 million in cash proceeds, consisting of approximately $15 million of the purchase price and $9 million for the purchaser’s share of accumulated costs. The remainder of the purchase price, plus accrued interest, is expected to be collected in 2010. SCEA has distributed the proceeds from the sale to the Dynegy Member and the LSP Member.
Note 13—Goodwill
The acquisition of the Contributed Entities on April 2, 2007 resulted in goodwill of $486 million. Changes in the carrying amount of goodwill for the year ended December 31, 2007 were as follows:
| December 31, 2007 |
||||||||||||||
| GEN-MW |
GEN-WE |
GEN-NE |
Total |
|||||||||||
| (in millions) | ||||||||||||||
| December 31, 2006 |
$ | — | $ | — | $ | — | $ | — | ||||||
| Acquisition of the Contributed Entities |
81 | 308 | 97 | 486 | ||||||||||
| Sale of CoGen Lyondell |
— | (48 | ) | — | (48 | ) | ||||||||
| December 31, 2007 |
$ | 81 | $ | 260 | $ | 97 | $ | 438 | ||||||
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DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Please read Note 3—Business Combinations and Acquisitions—LS Power Business Combination for further discussion of the acquisition and Note 4—Dispositions, Contract Terminations and Discontinued Operations—GEN-WE Discontinued Operations—CoGen Lyondell for further discussion of the sale of CoGen Lyondell.
Note 14—Intangible Assets
A summary of changes in our intangible assets is as follows:
| LS Power |
Sithe |
Rocky Road |
Total |
|||||||||||||
| (in millions) | ||||||||||||||||
| December 31, 2004 |
$ | — | $ | — | $ | — | $ | — | ||||||||
| Acquisition of Sithe |
— | 657 | — | 657 | ||||||||||||
| EITF 04-01 settlement |
— | (169 | ) | — | (169 | ) | ||||||||||
| Amortization expense |
— | (46 | ) | — | (46 | ) | ||||||||||
| December 31, 2005 |
$ | — | $ | 442 | $ | — | $ | 442 | ||||||||
| Acquisition of Rocky Road |
— | — | 29 | 29 | ||||||||||||
| Amortization expense |
— | (59 | ) | (7 | ) | (66 | ) | |||||||||
| December 31, 2006 |
$ | — | $ | 383 | $ | 22 | $ | 405 | ||||||||
| Acquisition of the Contributed Entities |
224 | — | — | 224 | ||||||||||||
| Amortization expense |
(8 | ) | (50 | ) | (9 | ) | (67 | ) | ||||||||
| December 31, 2007 |
$ | 216 | $ | 333 | $ | 13 | $ | 562 | ||||||||
LS Power. Pursuant to our acquisition of the Contributed Entities in April 2007, we recorded intangible assets of $224 million. This consisted of intangible assets of $192 million in GEN-MW and $32 million in GEN-WE. The intangible asset in GEN-MW relates to the value of the Plum Point Project as a result of the contracts related to power purchase agreements. This intangible asset will be amortized over the contractual term of 30 years, beginning when the facility becomes operational, which we expect to occur in 2010. The intangible assets for GEN-WE primarily relate to power tolling agreements that are being amortized over their respective contract terms ranging from 6 months to 7 years. The amortization expense is being recognized on the revenue line in our consolidated statements of operations, along with the revenues received from the contract. The estimated amortization expense for each of the five succeeding years is approximately $8 million, $8 million, $10 million, $7 million and $7 million, respectively. Please read Note 3—Business Combinations and Acquisitions—LS Power Business Combination for further discussion.
Sithe. Pursuant to our acquisition of Sithe Energies in February 2005, we recorded intangible assets of $657 million. This consisted primarily of a $488 million intangible asset related to a firm capacity sales agreement between Sithe Independence Power Partners and Con Edison, a subsidiary of Consolidated Edison, Inc. That contract provides Independence the right to sell 740 MW of capacity until 2014 at fixed prices that are currently above the prevailing market price of capacity for the New York Rest of State market. This asset will be amortized on a straight-line basis over the remaining life of the contract through October 2014. The amortization expense is being recognized in the revenue line on our consolidated statements of operations along with the revenues received from the contract. The annual amortization of the intangible asset is expected to approximate $50 million.
In addition, Independence holds a power tolling contract and a natural gas supply agreement with another of Dynegy’s subsidiaries, which were valued at $153 million and $16 million, respectively, as of January 31, 2005. Upon completion of Dynegy’s purchase of Independence, the power tolling agreement and the natural gas supply agreement were effectively settled, which resulted in a 2005 charge equal to their fair values, in accordance with EITF Issue 04-01. As a result, Dynegy recorded a 2005 pre-tax charge of $169 million, which is included in cost
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DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
of sales on our consolidated statements of operations. Upon settlement of the power tolling and natural gas supply agreements, the firm capacity sales agreement with Con Edison is the only remaining intangible asset associated with the acquisition of ExRes, which is included in intangibles and prepaids and other current assets on our consolidated balance sheets.
Please read Note 3—Business Combinations and Acquisitions—Sithe Energies Business Combination for further discussion.
Rocky Road Intangible Assets. Pursuant to our acquisition of NRG’s 50 percent ownership interest in the Rocky Road power plant, we recorded an intangible asset in the amount of $29 million. That amortization expense is being recognized in the revenue line on our consolidated statements of operations along with the revenues received from the contract based on a straight-line amortization over the remaining contractual term of the agreement. The annual amortization of the intangible asset is expected to be approximately $10 million. Please read Note 3—Business Combinations and Acquisitions—Rocky Road for further discussion.
Note 15—Debt
A summary of our long-term debt is as follows:
| December 31, | ||||||||||||
| 2007 |
2006 | |||||||||||
| Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value | |||||||||
| (in millions) | ||||||||||||
| Term Loan B, due 2013 |
$ | 70 | $ | 70 | $ | — | $ | — | ||||
| Term Facility, floating rate due 2013 |
850 | 850 | — | — | ||||||||
| Term facility, floating rate due 2012 |
— | — | 200 | 200 | ||||||||
| Senior Notes and Debentures: |
||||||||||||
| 6.875 percent due 2011 |
502 | 483 | 493 | 499 | ||||||||
| 8.75 percent due 2012 |
501 | 506 | 488 | 529 | ||||||||
| 7.5 percent due 2015 |
550 | 514 | — | — | ||||||||
| 8.375 percent due 2016 |
1,047 | 1,022 | 1,047 | 1,102 | ||||||||
| 7.125 percent due 2018 |
173 | 155 | 173 | 169 | ||||||||
| 7.75 percent due 2019 |
1,100 | 1,011 | — | — | ||||||||
| 7.625 percent due 2026 |
172 | 149 | 173 | 168 | ||||||||
| Second Priority Senior Secured Notes, 9.875 percent due 2010 |
— | — | 11 | 12 | ||||||||
| Subordinated Debentures payable to affiliates, 8.316 percent, due 2027 |
200 | 173 | 200 | 191 | ||||||||
| Sithe Senior Notes, 8.5 percent due 2007 |
— | — | 39 | 39 | ||||||||
| Sithe Senior Notes, 9.0 percent due 2013 |
388 | 416 | 409 | 446 | ||||||||
| Plum Point Credit Agreement Facility, floating rate due 2010 |
318 | 318 | — | — | ||||||||
| Plum Point Tax Exempt Bonds, floating rate due 2036 |
100 | 100 | — | — | ||||||||
| 5,971 | 3,233 | |||||||||||
| Unamortized premium on debt, net |
19 | 25 | ||||||||||
| 5,990 | 3,258 | |||||||||||
| Less: Amounts due within one year, including non-cash amortization of basis adjustments |
51 | 68 | ||||||||||
| Total Long-Term Debt |
$ | 5,939 | $ | 3,190 | ||||||||
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DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Aggregate maturities of the principal amounts of all long-term indebtedness as of December 31, 2007 are as follows: 2009—$58 million, 2010—$63 million, 2011—$570 million, 2012—$580 million and thereafter—$4,668 million.
Fifth Amended and Restated Credit Facility. On April 2, 2007, we entered into a fifth amended and restated credit facility (the “Fifth Amended and Restated Credit Facility”) with Citicorp USA, Inc. and JPMorgan Chase Bank, N.A., as co-administrative agents, JPMorgan Chase Bank, N.A., as collateral agent, Citicorp USA Inc., as payment agent, J.P. Morgan Securities Inc. and Citigroup Global Markets Inc., as joint lead arrangers and joint book-runners, and the other financial institutions party thereto as lenders or letter of credit issuers.
The Fifth Amended and Restated Credit Facility amended DHI’s former 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”).
Loans and letters of credit are available under the Revolving Facility and letters of credit are available under the Term L/C Facility for general corporate purposes. Letters of credit issued under DHI’s former credit facility have been continued under the Fifth Amended and Restated Credit Facility. The Term Loan B was used to pay a portion of the consideration under the Merger. In connection with the completion of the Merger, an aggregate $275 million under the Revolving Facility (subsequently repaid), 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.
The Fifth Amended and Restated Credit Facility is secured by certain assets of DHI and is guaranteed by Dynegy, Dynegy Illinois and certain subsidiaries of DHI. In addition, the obligations under the Fifth Amended and Restated Credit Facility and certain other obligations to the lenders thereunder and their affiliates are secured by substantially all of the assets of such guarantors. The Revolving Facility matures on April 2, 2012, and the Term L/C Facility and Term Loan B each mature on April 2, 2013. The principal amount of the Term L/C Facility is due in a single payment at maturity; the principal amount of Term Loan B is due in quarterly installments of $175,000 in arrears commencing December 31, 2007, with the unpaid balance due at maturity.
Borrowings under the Fifth Amended and Restated Credit Facility bear interest, at DHI’s option, at either the base rate, which is calculated as the higher of Citibank, N.A.’s publicly announced base rate and the federal funds rate in effect from time to time, or the Eurodollar rate (which is based on rates in the London interbank Eurodollar market), in each case plus an applicable margin.
The applicable margin for borrowings under the Revolving Facility depends on the Standard & Poor’s Ratings Services (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”) credit ratings of the Revolving Facility, with higher credit ratings resulting in a lower rate. The applicable margin for such borrowings will be either 0.125 percent or 0.50 percent per annum for base rate loans and either 1.125 percent or 1.50 percent per annum for Eurodollar loans, with the lower applicable margin being payable if the ratings for the Revolving Facility by S&P and Moody’s are BB+ and Ba1 or higher, respectively, and the higher applicable margin being payable if such ratings are less than BB+ and Ba1. The applicable margins for the Term L/C Facility and Term Loan B are 0.50 percent for base rate loans and 1.50 percent for Eurodollar loans.
An unused commitment fee of either 0.25 percent or 0.375 percent is payable on the unused portion of the Revolving Facility, with the lower commitment fee being payable if the ratings for the Revolving Facility by S&P and Moody’s are BB+ and Ba1 or higher, respectively, and the higher commitment fee being payable if such ratings are less than BB+ and Ba1.
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DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The Fifth Amended and Restated Credit Facility contains mandatory prepayment provisions associated with specified asset sales and dispositions (including as a result of casualty or condemnation). The Fifth Amended and Restated Credit Facility also contains customary affirmative and negative covenants and events of default. Subject to certain exceptions, DHI and its subsidiaries are subject to restrictions on incurring additional indebtedness, limitations on investments and certain limitations on dividends and other payments in respect of capital stock.
The Fifth Amended and Restated Credit Facility also contains certain financial covenants, including (i) a covenant (measured as of the last day of the relevant fiscal quarter as specified below) that requires DHI and certain of its subsidiaries to maintain a ratio of secured debt to adjusted earnings before interest, taxes, depreciation and amortization (“EBITDA”) for DHI and its relevant subsidiaries of no greater than 2.75:1 (December 31, 2007 and thereafter through and including March 31, 2009); and 2.5:1 (June 30, 2009 and thereafter); and (ii) a covenant that requires DHI and certain of its subsidiaries to maintain a ratio of adjusted EBITDA to consolidated interest expense for DHI and its relevant subsidiaries as of the last day of the measurement periods ending December 31, 2007 and thereafter through and including December 31, 2008 of no less than 1.5:1; ending March 31, 2009 and June 30, 2009 of no less than 1.625:1; and ending September 30, 2009 and thereafter of no less than 1.75:1.
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, which 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 Term Loan B. The Credit Agreement Amendment also amended a pro forma leverage ratio requirement in the Fifth Amended and Restated Credit Facility to allow DHI to issue the Notes (as defined and discussed below).
Senior Notes. On April 12, 2006, DHI issued $750 million aggregate principal amount of our 8.375 percent Senior Unsecured Notes due 2016 (the “New Senior Notes”) in a private offering (the “Senior Notes Offering”). The New Senior Notes are not redeemable at our option prior to maturity. The New Senior Notes are our senior unsecured obligations of DHI and rank equal in right of payment to all of DHI’s existing and future senior unsecured indebtedness, and are senior to all of our existing and any of our future subordinated indebtedness. Dynegy did not guarantee the New Senior Notes, and the assets that Dynegy owns (principally its interest in DLS Power Holdings and DLS Power Development) do not support the New Senior Notes. The proceeds from the Senior Notes Offering, together with cash on hand, were used to fund the SPN Tender Offer discussed below. On September 14, 2006, DHI exchanged the New Senior Notes for a new issue of substantially identical notes registered under the Securities Act of 1933.
On May 24, 2007, DHI issued $1.1 billion aggregate principal amount of its 7.75 percent Senior Unsecured Notes due 2019 (the “2019 Notes) and $550 million aggregate principal amount of its 7.50 percent Senior Unsecured Notes due 2015 (the “2015 Notes” and, together with the 2019 Notes, the “Notes”) pursuant to the terms of a purchase agreement, dated as of May 17, 2007, by and among DHI and the several initial purchasers party thereto (the “Purchasers”). The Notes are senior unsecured obligations and rank equal in right of payment to all of DHI’s existing and future senior unsecured indebtedness, and are senior to all of DHI’s existing, and any of its future, subordinated indebtedness. DHI’s secured debt and its other secured obligations are effectively senior to the Notes to the extent of the value of the assets securing such debt or other obligations. None of DHI’s subsidiaries have guaranteed the Notes and, as a result, all of the existing and future liabilities of DHI’s subsidiaries are effectively senior to the Notes. Dynegy has not guaranteed the Notes, and the assets that Dynegy owns through its subsidiaries, other than DHI, do not support the Notes. In connection with the Notes, DHI entered into a registration rights agreement with the Purchasers of the Notes pursuant to which DHI agreed to offer to exchange the Notes for a new issue of substantially identical notes registered under the Securities Act of
F-49
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
1933. On October 15, 2007, pursuant to the registration rights agreement, DHI initiated the exchange offer, which was completed in the fourth quarter 2007.
DHI used the net proceeds from the sale of the Notes to repay a portion of the debt assumed in the Merger. Long-term debt assumed upon completion of the Merger and repaid from the proceeds of the sale of the Notes consisted of the following as of April 2, 2007:
| Face Value |
Premium Discount |
Fair Value | ||||||||
| (in millions) | ||||||||||
| Generation Facilities First Lien Term Loans due 2013 |
$ | 919 | $ | 1 | $ | 920 | ||||
| Generation Facilities Second Lien Term Loans due 2014 |
150 | 1 | 151 | |||||||
| Kendall First Lien Term Loan due 2013 |
396 | (5 | ) | 391 | ||||||
| Ontelaunee First Lien Term Loan due 2009 |
100 | (1 | ) | 99 | ||||||
| Ontelaunee Second Lien Credit Agreement due 2009 |
50 | 1 | 51 | |||||||
| Total debt repaid with proceeds from unsecured offering |
$ | 1,615 | $ | (3 | ) | $ | 1,612 | |||
Outstanding letters of credit under the above mentioned LC facilities were transferred to, and became outstanding letters of credit under, the Fifth Amended and Restated Credit Facility as amended by the Credit Agreement Amendment. Continuing secured obligations of Dynegy Gen Finance Co LLC include financially settled heat rate options and a collateral posting arrangement that are secured by the assets of Dynegy Gen Finance Co LLC.
Second Priority Senior Secured Notes. On April 12, 2006, we completed a cash tender offer and consent solicitation (the “SPN Tender Offer”), in which we purchased $151 million of our $225 million Second Priority Senior Secured Floating Rate Notes due 2008 (the “2008 Notes”), $614 million of our $625 million 9.875 percent Second Priority Senior Secured Notes due 2010 (the “2010 Notes”) and all $900 million of our 10.125 percent Second Priority Senior Secured Notes due 2013 (the “2013 Notes” and collectively with the “2008 Notes” and the “2010 Notes,” the “Second Priority Notes”). In connection with the SPN Tender Offer, we amended the indenture under which the Second Priority Notes were issued to eliminate or modify substantially all of the restrictive covenants, certain events of default and related provisions and release certain liens securing the obligations of DHI and the guarantors of the Second Priority Notes.
Total cash paid to repurchase the $1,664 million of Second Priority Notes, including consent fees and accrued interest, was $1,904 million. We recorded a charge of approximately $228 million in 2006 associated with this transaction, of which $202 million is included in debt conversion costs, and $26 million of acceleration of amortization of financing costs and write-offs of discounts and premiums is included in interest expense on our consolidated statements of operations.
On July 15, 2006, we redeemed the remaining $74 million of our 2008 Notes, at a redemption price of 103 percent of the principal amount, plus accrued and unpaid interest to the redemption date. The interest rate on the 2008 Notes was based on three-month LIBOR plus 650 basis points. We recorded a charge of approximately $2 million in 2006 associated with this transaction, which is included in debt conversion costs in our consolidated statements of operations.
On September 7, 2007, we completed the redemption of $11 million of DHI’s remaining outstanding 2010 Notes at a redemption price of 104.938 percent of the principal amount plus accrued and unpaid interest to the date of redemption.
F-50
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Subordinated Debentures. In May 1997, NGC Corporation Capital Trust I (“Trust”) issued, in a private transaction, $200 million aggregate liquidation amount of 8.316 percent Subordinated Capital Income Securities (“Trust Securities”) representing preferred undivided beneficial interests in the assets of the Trust. The Trust invested the proceeds from the issuance of the Trust Securities in an equivalent amount of DHI’s 8.316 percent Subordinated Debentures (“Subordinated Debentures”). The sole assets of the Trust are the Subordinated Debentures. The Trust Securities are subject to mandatory redemption in whole, but not in part, on June 1, 2027, upon payment of the Subordinated Debentures at maturity, or in whole, but not in part, at any time, contemporaneously with the optional prepayment of the Subordinated Debentures, as allowed by the associated indenture. The Subordinated Debentures are redeemable, at DHI’s option, at specified redemption prices. The Subordinated Debentures represent DHI’s unsecured obligations and rank subordinate and junior in right of payment to all of DHI’s senior indebtedness to the extent and in the manner set forth in the associated indenture. We have irrevocably and unconditionally guaranteed, on a subordinated basis, payment for the benefit of the holders of the Trust Securities the obligations of the Trust to the extent the Trust has funds legally available for distribution to the holders of the Trust Securities. Since the Trust is considered a VIE, and the holders of the Trust Securities absorb a majority of the Trust’s expected losses, DHI’s obligation is represented by the Subordinated Debentures payable to the deconsolidated Trust. We may defer payment of interest on the Subordinated Debentures as described in the indenture, although we have not yet done so and have continued to pay interest as and when due. As of December 31, 2007 and 2006, the redemption amount associated with these securities totaled $200 million.
Sithe Senior Notes. On January 31, 2005, we completed the acquisition of ExRes, the parent company of Sithe Energies and Independence. Upon the closing, we consolidated $919 million in face value project debt, which was recorded at its fair value of $797 million as of January 31, 2005, for which certain of the entities acquired are obligated. Please read Note 3—Business Combinations and Acquisitions—Sithe Energies Business Combination for further discussion of this transaction.
Long-term debt consolidated upon completion of the Sithe Energies acquisition consisted of the following as of January 31, 2005:
| Face Value |
Premium (Discount) |
Fair Value | ||||||||
| (in millions) | ||||||||||
| Subordinated Debt, 7.0 percent due 2034 |
$ | 419 | $ | (167 | ) | $ | 252 | |||
| Senior Notes, 8.5 percent due 2007 |
91 | 3 | 94 | |||||||
| Senior Notes, 9.0 percent due 2013 |
409 | 42 | 451 | |||||||
| Total Independence Debt |
$ | 919 | $ | (122 | ) | $ | 797 | |||
The senior debt and subordinated debt are secured by substantially all of the assets of Independence, but are not guaranteed by us. The difference of $122 million between the face value and the fair value of the Independence Debt that was recognized upon the acquisition of ExRes will be accreted into interest expense over the life of the debt.
The terms of the indenture governing the senior debt, among other things, prohibit cash distributions by Independence to its affiliates, including Dynegy, unless certain project reserve accounts are funded to specified levels and the required debt service coverage ratio is met. The indenture also includes other covenants and restrictions, relating to, among other things, prohibitions on asset dispositions and fundamental changes, reporting requirements and maintenance of insurance.
F-51
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
On July 21, 2006, DHI executed and consummated an exchange agreement (the “Exchange Agreement”), by and among DHI and RCP Debt, LLC and RCMF Debt, LLC (together, the “Reservoir Entities”). Pursuant to the Exchange Agreement, the Reservoir Entities exchanged approximately $419 million principal amount of the subordinated debt of Independence, together with all claims for accrued and unpaid interest thereon and all other rights and all obligations of the Reservoir Entities under the agreement pursuant to which the subordinated debt was issued (together, the “Sithe Debt”), for approximately $297 million principal amount of DHI’s 8.375 percent Senior Unsecured Notes due 2016 (the “Additional Notes”). The Additional Notes have terms and conditions identical to, and are fungible for trading and other purposes with, the $750 million aggregate principal amount of the New Senior Notes issued on April 12, 2006. On September 14, 2006, DHI exchanged the Additional Notes for a new issue of substantially identical notes registered under the Securities Act of 1933. We recorded a charge of approximately $36 million in 2006 associated with this transaction, which is included in interest expense in our consolidated statements of operations.
Plum Point Credit Agreement Facility. The Plum Point Credit Agreement Facility (“Credit Agreement Facility”) consists of a $700 million construction loan (the “Construction Loan”), a $700 million term loan commitment (the “Bank Loan”), a $17 million revolving credit facility (the “Revolver”) and a $102 million backstop letter of credit facility (the “LC Facility”). The LC Facility was initially utilized to back-up the $101 million letter of credit issued under the then-existing LC Facility (the “Original LC”) for the benefit of the owners of the Tax Exempt Bonds described below. During the second quarter 2007, the Tax Exempt Bonds were repaid and reoffered and a new letter of credit in the amount of approximately $101 million was issued under the LC Facility in substitution for the Original LC. Borrowings under the Credit Agreement Facility bear interest, at Plum Point’s option, at either the base rate, which is determined as the greater of the Prime Rate or the Federal Funds Rate in effect from time to time plus 1/2 of 1 percent, or Adjusted LIBOR, which is equal to the product of the applicable LIBOR and any Statutory Reserves plus an applicable margin equal to 0.35 percent. In addition, Plum Point pays commitment fees equal to 0.125 percent per annum on the undrawn Bank Loan, Revolver and LC Facility commitments. Upon completion of the construction of the Plum Point Project, the Construction Loan will terminate and the debt thereunder will be replaced by the Bank Loan. The Bank Loan matures on the thirtieth anniversary of the later of the date on which substantial completion of the facility has occurred or the first date of commercial operation under any of the power purchase agreements then in effect. The expected commercial operations date is August 2010.
The payment obligations of Plum Point in respect of the Bank Loan, the Revolver, the LC Facility, and associated interest rate hedging agreements (discussed below) are unconditionally and irrevocably guaranteed by Ambac Assurance Corporation. Ambac Assurance Corporation also provided an unconditional commitment to issue, upon the closing of any refinancing of the Tax Exempt Bonds, a bond insurance policy insuring the Tax Exempt Bonds and a debt service reserve surety in an amount equal to the debt service reserve requirement with respect to such bonds. The credit facilities and insurance policy are secured by a mortgage and security interest (subject to permitted liens) in all of Plum Point’s assets and contract rights and Plum Point’s undivided tenancy in common interest in the Plum Point Project and PPEA’s interest in Plum Point. Plum Point pays an additional 0.38 percent spread for the AMBAC insurance coverage, which is deemed a cost of financing and included in interest expense.
In the second quarter 2007, Plum Point entered into three interest rate swap agreements with an initial aggregate notional amount of approximately $183 million and fixed interest rates of approximately 5.3 percent. These interest rate swap agreements convert Plum Point’s floating rate debt exposure (exclusive of that on the Tax Exempt Bonds) to a fixed interest rate. The interest rate swap agreements expire in June 2040. During 2007, we recorded $27 million of mark-to-market income related to these interest rate swap agreements as an offset to our consolidated interest expense. Effective July 1, 2007, we designated these agreements as cash flow hedges.
F-52
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Therefore, changes in value after that date are reflected in Other Comprehensive Income (Loss), and subsequently reclassified to interest expense contemporaneously with the related interest expense, or depreciation expense in the event the interest was capitalized, in either case to the extent of hedge effectiveness.
Plum Point Tax Exempt Bonds. On April 1, 2006, the City of Osceola (the “City”) loaned the $100 million in proceeds of a tax exempt bond issuance (the “Tax Exempt Bonds”) to Plum Point. The Tax Exempt Bonds were issued pursuant to and secured by a Trust Indenture dated April 1, 2006 between the City and Regions Bank as Trustee. The purpose of the Tax Exempt Bonds is to finance certain of Plum Point’s undivided interests in various sewage and solid waste collection and disposal facilities in the Plum Point facility. Interest expense on the Tax Exempt Bonds is based on a weekly variable rate and is payable monthly. The interest rate in effect at December 31, 2007 was 3.50 percent. The Tax Exempt Bonds mature on April 1, 2036.
Convertible Subordinated Debentures due 2023. On May 15, 2006, we converted all $225 million of our outstanding 4.75 percent Convertible Subordinated Debentures due 2023 into shares of our Class A common stock (the “Convertible Debenture Exchange”). In this transaction, we issued an aggregate of 54,598,369 shares of our Class A common stock and paid the debenture holders an aggregate of approximately $47 million in premiums and accrued and unpaid interest using cash on hand. We recorded a charge of approximately $44 million in 2006 associated with this transaction, which is included in debt conversion costs in our consolidated statements of operations.
Restricted Cash and Investments. The following table depicts our restricted cash and investments as of December 31, 2007 and 2006:
| December 31, | ||||||
| 2007 |
2006 | |||||
| (in millions) | ||||||
| Credit facility (1) |
$ | 850 | $ | 200 | ||
| Sithe Energy (2) |
41 | 163 | ||||
| Plum Point (3) |
54 | — | ||||
| GEN Finance (4) |
57 | — | ||||
| Sandy Creek (5) |
323 | — | ||||
| Total restricted cash and investments |
$ | 1,325 | $ | 363 | ||
| (1) | Includes cash posted to support the letter of credit component of our credit facility. We are required to post cash collateral in an amount equal to 103 percent of outstanding letters of credit. |
| (2) | Includes amounts related to the terms of the indenture governing the Sithe Senior Debt, which among other things, prohibit cash distributions by Independence to its affiliates, including us, unless certain project reserve accounts are funded to specified levels and the required debt service coverage ratio is met. |
| (3) | Includes proceeds from the Tax Exempt Bonds. These funds are used to finance PPEA’s undivided interest in various sewage and solid waste collection and disposal facilities which are under construction. Funds will be drawn from the restricted accounts as necessary for the construction of these facilities. |
| (4) | Includes amounts restricted under the terms of a security and deposit agreement associated with a collateral agreement and commodity hedges entered into by GEN Finance. |
| (5) | Includes amounts related to our funding commitment related to the Sandy Creek Project. Please read Note 12—Variable Interest Entities—Sandy Creek. |
F-53
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Note 16—Related Party Transactions
Transactions with Chevron
On April 2, 2007, in connection with the Merger, the ownership interest of Chevron U.S.A. Inc. (“CUSA”) was reduced from approximately 20 percent to approximately 12 percent and CUSA’s shares automatically converted into Class A shares. On May 24, 2007, CUSA completed the sale of its 96,891,014 shares of Dynegy’s Class A common stock in an underwritten public offering.
Transactions with CUSA consisted of purchases and sales of natural gas and natural gas liquids between our affiliates and CUSA. We believe that these transactions were executed on terms that were fair and reasonable. During the years ended December 31, 2007, 2006 and 2005, we recognized net purchases from CUSA of $22 million, $52 million and $45 million, respectively. In accordance with the net presentation provisions of EITF Issue 02-3, all of these transactions, whether physically or financially settled, have been presented net on the consolidated statements of operations. In addition, during the years ended December 31, 2007, 2006 and 2005, our other businesses recognized aggregate sales to CUSA of zero, zero and $1.2 billion, respectively, and aggregate purchases of approximately zero, zero and $1 billion, respectively, which are reflected gross on the consolidated statements of operations.
Series C Convertible Preferred Stock. In August 2003, Dynegy issued to CUSA 8 million shares of its Series C Convertible Preferred Stock due 2033 (“Series C Preferred”). Dynegy accrued dividends on the Series C Preferred at a rate of 5.5 percent of the liquidation value per annum. In May 2006, Dynegy redeemed all of the outstanding shares of its Series C Preferred, which were held by CUSA. In order to redeem the Series C Preferred, Dynegy paid CUSA $400 million in cash, plus accrued and unpaid dividends totaling approximately $6.3 million. Dynegy used approximately $178 million in net proceeds from an equity offering of 40.25 million shares of its Class A common stock that closed on the same day (including net proceeds of $23 million from the underwriters’ exercise of their option to purchase an additional 5.25 million shares), with the balance funded from cash on hand and a cash dividend of $50 million from DHI. The redemption of the Series C Preferred eliminated the associated $22 million annual preferred dividend and reduced the number of diluted shares of Dynegy’s common stock outstanding.
Equity Investments. We hold an investment in a joint venture in which CUSA or its affiliates are also investors. The investment is a 50 percent ownership interest in Black Mountain, which owns the Black Mountain power generation facility. Prior to the sale of DMSLP, we previously held a 22.9 percent ownership interest in VESCO, a venture that operates a natural gas liquids processing, extraction, fractionation and storage facility in the Gulf Coast region, in which CUSA or its affiliates are also investors. During the years ended December 31, 2007, 2006 and 2005, our portion of the net income from joint ventures with CUSA was approximately $7 million, $8 million and $8 million, respectively.
Other
Equity Investments. We also hold three investments in joint ventures in which LS Power or its affiliates are also investors. Dynegy has a 50 percent ownership interest in DLS Power Holdings and DLS Power Development. DHI has a 50 percent ownership interest in SCEA, which was contributed to it by Dynegy in August 2007. Please read Note 12—Variable Interest Entities for further discussion.
We also purchase and sell, or have purchased or sold, natural gas, natural gas liquids, crude oil, emissions and power and, in some instances, earn management fees from certain entities in which we have equity investments. During the years ended December 31, 2007, 2006 and 2005, we recognized net sales to affiliates
F-54
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
related to these transactions of zero, zero and $200 million, respectively. In accordance with the net presentation provisions of EITF Issue 02-3, all of these transactions, whether physically or financially settled, have been presented net in the consolidated statements of operations. In addition, during the years ended December 31, 2007, 2006 and 2005, our other businesses recognized aggregate sales to these affiliates of zero, zero and $4 million, respectively, and aggregate purchases of zero, zero and $135 million, respectively, which are reflected gross in the consolidated statements of operations. Revenues were related to the supply of fuel for use at generation facilities, primarily West Coast Power, and the supply of natural gas sold by retail affiliates. Expenses primarily represent the purchase of natural gas liquids that were subsequently sold in our marketing operations.
December 2001 Equity Purchases. In December 2001, ten former members of our senior management purchased Class A common stock from Dynegy in a private placement pursuant to Section 4(2) of the Securities Act of 1933. These former officers received loans from Dynegy totaling approximately $25 million to purchase Dynegy’s common stock at a price of $19.75 per share, the same price as the net proceeds per share received by Dynegy from a concurrent public offering. The loans bear interest at 3.25 percent per annum and are full recourse to the borrowers. Such loans are accounted for as subscriptions receivable within Dynegy’s stockholders’ equity on the consolidated balance sheets.
Other. During 2007, DHI paid dividends of $342 million to Dynegy.
On April 2, 2007, Dynegy contributed to Dynegy Illinois its interest in the Contributed Entities. Also in April 2007, Dynegy Illinois contributed to DHI all of its interest in New York Holdings, together with its indirect interest in the subsidiaries of New York Holdings. Please read Note 3—Business Combinations and Acquisitions—LS Power Business Combination for further discussion. In August 2007, Dynegy contributed to DHI its 50 percent interest in SCH. Please read Note 12—Variable Interest Entities—Sandy Creek for further information.
During 2006, DHI repaid a $120 million borrowing from Dynegy. Also during 2006, DHI made a one time dividend payment of $50 million to Dynegy from the proceeds of the Term Loan. Please read Note 15—Debt for further discussion.
In the normal course of business, payments are made or cash is received by DHI on behalf of Dynegy, or by Dynegy on behalf of DHI. As a result of such transactions, DHI has recorded over time a receivable from Dynegy in the aggregate amount of $825 million at December 31, 2007. DHI has resolved, effective December 31, 2007, that it will memorialize and distribute this receivable balance to Dynegy, once all required third-party approvals have been obtained. As such, this receivable has been reclassified to equity on DHI’s consolidated balance sheet as of December 31, 2007.
Note 17—Income Taxes
Income Tax (Expense) Benefit-Dynegy. We are subject to U.S. federal, foreign and state income taxes on our operations.
Dynegy’s components of income (loss) from continuing operations before income taxes were as follows:
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| (in millions) | ||||||||||||
| Income (loss) from continuing operations before income taxes: |
||||||||||||
| Domestic |
$ | 273 | $ | (478 | ) | $ | (1,203 | ) | ||||
| Foreign |
(6 | ) | 5 | 10 | ||||||||
| $ | 267 | $ | (473 | ) | $ | (1,193 | ) | |||||
F-55
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Dynegy’s components of income tax (expense) benefit related to income (loss) from continuing operations were as follows:
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| (in millions) | ||||||||||||
| Current tax benefit (expense): |
||||||||||||
| Domestic |
$ | (22 | ) | $ | (3 | ) | $ | 3 | ||||
| Foreign |
— | (2 | ) | — | ||||||||
| Deferred tax benefit (expense): |
||||||||||||
| Domestic |
(132 | ) | 148 | 404 | ||||||||
| Foreign |
3 | 9 | (14 | ) | ||||||||
| Income tax (expense) benefit |
$ | (151 | ) | $ | 152 | $ | 393 | |||||
Dynegy’s income tax (expense) benefit related to income (loss) from continuing operations for the years ended December 31, 2007, 2006 and 2005, was equivalent to effective rates of 57 percent, 32 percent and 33 percent, respectively. Dynegy realized a higher state income tax expense in 2007 as a result of adjusting Dynegy’s accumulated temporary differences to a higher overall effective state tax rate. The impact of the increase in our estimate of the state tax rate for Dynegy was a reduction in net income of approximately $50 million, or $0.07 per share. This increase was partially offset by the impact of various state tax law changes. 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. Differences between taxes computed at the U.S. federal statutory rate and Dynegy’s reported income tax benefit were as follows:
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| (in millions) | ||||||||||||
| Expected tax (expense) benefit at U.S. statutory rate (35%) |
$ | (94 | ) | $ | 166 | $ | 418 | |||||
| State taxes |
(55 | ) | 32 | 18 | ||||||||
| Foreign taxes |
3 | (6 | ) | 2 | ||||||||
| Valuation allowance |
— | (4 | ) | (33 | ) | |||||||
| IRS and state audits and settlements |
(3 | ) | (38 | ) | (3 | ) | ||||||
| Basis differentials and other |
(2 | ) | 2 | (9 | ) | |||||||
| Income tax (expense) benefit |
$ | (151 | ) | $ | 152 | $ | 393 | |||||
Income Tax (Expense) Benefit-DHI. DHI’s components of income (loss) from continuing operations before income taxes were as follows:
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| (in millions) | ||||||||||||
| Income (loss) from continuing operations before income taxes: |
||||||||||||
| Domestic |
$ | 298 | $ | (426 | ) | $ | (1,101 | ) | ||||
| Foreign |
(6 | ) | 5 | — | ||||||||
| $ | 292 | $ | (421 | ) | $ | (1,101 | ) | |||||
F-56
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DHI’s components of income tax (expense) benefit related to income (loss) from continuing operations were as follows:
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| (in millions) | ||||||||||||
| Current tax benefit (expense): |
||||||||||||
| Domestic |
$ | (11 | ) | $ | (1 | ) | $ | 4 | ||||
| Foreign |
— | (2 | ) | — | ||||||||
| Deferred tax benefit (expense): |
||||||||||||
| Domestic |
(108 | ) | 119 | 385 | ||||||||
| Foreign |
3 | 9 | (15 | ) | ||||||||
| Income tax (expense) benefit |
$ | (116 | ) | $ | 125 | $ | 374 | |||||
DHI’s income tax (expense) benefit related to income (loss) from continuing operations for the years ended December 31, 2007, 2006 and 2005, was equivalent to effective rates of 40 percent, 30 percent and 34 percent, respectively. DHI realized a higher state income tax expense in 2007 as a result of adjusting DHI’s accumulated temporary differences to a higher overall effective state tax rate. The impact of the increase in our estimate of the state tax rate for DHI was a reduction in net income of approximately $25 million. This increase was partially offset by the impact of various state tax law changes. 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. Differences between taxes computed at the U.S. federal statutory rate and DHI’s reported income tax benefit were as follows:
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| (in millions) | ||||||||||||
| Expected tax benefit at U.S. statutory rate (35%) |
$ | (102 | ) | $ | 147 | $ | 385 | |||||
| State taxes |
(21 | ) | 17 | 22 | ||||||||
| Foreign taxes |
3 | (6 | ) | (2 | ) | |||||||
| Valuation allowance |
— | (4 | ) | (14 | ) | |||||||
| IRS and state audits and settlements |
8 | (38 | ) | (5 | ) | |||||||
| Reserves legal |
— | — | (11 | ) | ||||||||
| Basis differentials and other |
(4 | ) | 9 | (1 | ) | |||||||
| Income tax (expense) benefit |
$ | (116 | ) | $ | 125 | $ | 374 | |||||
F-57
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Deferred Tax Liabilities and Assets. Our significant components of deferred tax assets and liabilities were as follows:
| Dynegy |
DHI |
|||||||||||||||
| Year ended December 31, |
Year ended December 31, |
|||||||||||||||
| 2007 |
2006 |
2007 |
2006 |
|||||||||||||
| (in millions) | ||||||||||||||||
| Deferred tax assets: |
||||||||||||||||
| Current: |
||||||||||||||||
| Reserves (legal, environmental and other) |
$ | 28 | $ | 15 | $ | 28 | $ | — | ||||||||
| NOL carryforwards |
58 | 95 | 48 | 52 | ||||||||||||
| Subtotal |
86 | 110 | 76 | 52 | ||||||||||||
| Less: valuation allowance |
(18 | ) | (7 | ) | (16 | ) | (4 | ) | ||||||||
| Total current deferred tax assets |
68 | 103 | 60 | 48 | ||||||||||||
| Non-current: |
||||||||||||||||
| NOL carryforwards |
97 | 317 | 86 | 262 | ||||||||||||
| AMT credit carryforwards |
262 | 251 | — | — | ||||||||||||
| Capital loss carryforward |
17 | 17 | 17 | 17 | ||||||||||||
| Foreign tax credits |
24 | 23 | 21 | 20 | ||||||||||||
| Reserves (legal, environmental and other) |
53 | 51 | 53 | 48 | ||||||||||||
| Miscellaneous book/tax recognition differences |
60 | 9 | 56 | 10 | ||||||||||||
| Subtotal |
513 | 668 | 233 | 357 | ||||||||||||
| Less: valuation allowance |
(44 | ) | (62 | ) | (43 | ) | (62 | ) | ||||||||
| Total non-current deferred tax assets |
469 | 606 | 190 | 295 | ||||||||||||
| Deferred tax liabilities: |
||||||||||||||||
| Current: |
||||||||||||||||
| Miscellaneous book/tax recognition differences |
23 | 10 | 30 | — | ||||||||||||
| Total current deferred tax liabilities |
23 | 10 | 30 | — | ||||||||||||
| Non-current: |
||||||||||||||||
| Depreciation and other property differences |
1,640 | 903 | 1,184 | 588 | ||||||||||||
| Power contract |
75 | 143 | 54 | — | ||||||||||||
| Other |
— | 17 | — | 20 | ||||||||||||
| Total non-current deferred tax liabilities |
1,715 | 1,063 | 1,238 | 608 | ||||||||||||
| Net deferred tax liability |
$ | 1,201 | $ | 364 | $ | 1,018 | $ | 265 | ||||||||
F-58
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOL Carryforwards—Dynegy. At December 31, 2007, Dynegy had approximately $261 million of regular federal tax NOL carryforwards after considering the effect of carryback to prior years and $1,242 million of AMT NOL carryforwards. The federal and AMT NOL carryforwards will expire beginning in 2024 through 2027, respectively. As a result of the application of certain provisions of the Internal Revenue Code, Dynegy incurred an ownership change in May 2007 that placed an annual limitation on its ability to utilize certain tax carryforwards, including its NOL carryforwards. We do not expect that the ownership change will have a material impact on Dynegy’s tax liability. There was no valuation allowance established at December 31, 2007 for Dynegy’s federal NOL carryforwards, as management believes Dynegy’s NOL carryforward is more likely than not to be fully realized in the future based, among other things, on management’s estimates of future taxable net income, future reversals of existing taxable temporary differences and tax planning.
At December 31, 2007, state NOL carryforwards were as follows:
| Amount (in millions) |
Expiration Dates | ||||
| States where we file unitary state income tax returns: |
|||||
| Illinois |
$ | 54 | 2015 & 2018 | ||
| California |
23 | 2023 & 2026 | |||
| States where we file separate state income tax returns: |
|||||
| Louisiana |
178 | 2020 – 2027 | |||
| New York |
639 | 2021 – 2026 | |||
| Kentucky |
245 | 2021 – 2027 | |||
| Iowa |
24 | 2022 – 2026 | |||
| Georgia |
58 | 2022 – 2027 | |||
| Pennsylvania |
68 | 2022 – 2027 | |||
| Other |
10 | 2007 – 2027 | |||
| Total |
$ | 1,299 | |||
At December 31, 2007 and 2006, foreign NOL carryforwards totaled $1 million and $11 million, respectively.
NOL Carryforwards—DHI. At December 31, 2007, DHI had approximately $204 million of regular federal tax NOL carryforwards after considering the effect of carryback to prior years and $885 million of AMT NOL carryforwards. The federal NOL carryforwards will expire beginning in 2024. As a result of the application of certain provisions of the Internal Revenue Code, Dynegy incurred an ownership change in May 2007 that placed an annual limitation on its ability to utilize certain tax carryforwards, including its NOL carryforwards. We do not expect that the ownership change will have a material impact on DHI’s tax liability. There was no valuation allowance established at December 31, 2007 for DHI’s federal NOL carryforwards, as management believes DHI’s NOL carryforward is more likely than not to be fully realized in the future based, among other things, on management’s estimates of future taxable net income, future reversals of existing taxable temporary differences and tax planning.
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At December 31, 2007, state NOL carryforwards were as follows:
| Amount (in millions) |
Expiration Dates | ||||
| States where we file unitary state income tax returns: |
|||||
| Illinois |
$ | 44 | 2015 & 2018 | ||
| California |
23 | 2023 & 2026 | |||
| States where we file separate state income tax returns: |
|||||
| Louisiana |
178 | 2020 – 2027 | |||
| New York |
639 | 2021 – 2026 | |||
| Kentucky |
245 | 2021 – 2027 | |||
| Iowa |
24 | 2022 – 2026 | |||
| Georgia |
58 | 2022 – 2027 | |||
| Pennsylvania |
68 | 2022 – 2027 | |||
| Other |
10 | 2007 – 2027 | |||
| Total |
$ | 1,289 | |||
At December 31, 2007 and 2006, foreign NOL carryforwards totaled $1 million and $11 million, respectively.
AMT Credit Carryforwards. At December 31, 2007, Dynegy had approximately $262 million of AMT credit carryforwards. The AMT credit carryforwards do not expire. There was no valuation allowance established at December 31, 2007 for Dynegy’s AMT credit carryforwards, as management believes the AMT credit carryforward is more likely than not to be fully realized in the future based, among other things, on management’s estimates of future taxable net income and future reversals of existing taxable temporary differences.
Capital Loss Carryforwards. At December 31, 2007, we had approximately $49 million of federal capital loss carryforwards. The capital loss carryforwards expire during 2008 and 2009. At December 31, 2007, we had a full valuation allowance against our capital loss carryforwards, which management believes are not likely to be fully realized in the future based on our ability to generate capital gains.
Foreign Tax Credits. At December 31, 2007 and 2006, Dynegy had approximately $24 and $23 million of foreign tax credits. The foreign tax credits expire in 2010 through 2014. At December 31, 2007, a full valuation allowance for Dynegy’s foreign tax credits was recorded as it has disposed of or discontinued the majority of its foreign operations and management believes the foreign tax credits are not likely to be fully realized in the future based on its ability to generate foreign source income. Unless Dynegy generates foreign source income prior to their expiration, which management does not anticipate, Dynegy will write-off the $24 million of foreign tax credits and the related $24 million valuation allowance in the year of their expiration.
At December 31, 2007 and 2006, DHI had approximately $21 and $20 million of foreign tax credits. The foreign tax credits expire in 2010 through 2014. At December 31, 2007, a full valuation allowance for DHI’s foreign tax credits was recorded as it has disposed of or discontinued the majority of its foreign operations and management believes the foreign tax credits are not likely to be fully realized in the future based on its ability to generate foreign source income. Unless DHI generates foreign source income prior to their expiration, which management does not anticipate, DHI will write-off the $21 million of foreign tax credits and the related $21 million valuation allowance in the year of their expiration.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Residual U.S. Income Tax on Foreign Earnings. We do not have material undistributed non-previously taxed earnings from our foreign operations, and therefore, we have not provided any U.S. deferred taxes or foreign withholding taxes on the actual or deemed remittance of any such earnings.
Change in Valuation Allowance. Realization of our deferred tax assets is dependent upon, among other things, our ability to generate taxable income of the appropriate character in the future. At December 31, 2007, valuation allowances related to capital loss carryforwards, foreign tax credit carryforwards and state NOL carryforwards have been established. During 2007, we decreased our valuation allowance associated with various state NOL carryforwards, and increased our valuation allowance on foreign tax credit carryforwards. During 2006, we increased our valuation allowance associated with various state NOL carryforwards and released a valuation allowance on foreign NOL carryforwards. In 2005, as a result of the sale of DMSLP, as further discussed in Note 4—Dispositions, Contract Terminations and Discontinued Operations—Other Discontinued Operations—Natural Gas Liquids, we reduced the valuation allowance related to our capital loss carryforward. We also increased our valuation allowance associated with a state NOL carryforward and established a valuation allowance on a foreign NOL carryforward.
The changes in the valuation allowance by attribute for Dynegy were as follows:
| Capital Loss Carryforwards |
Foreign Tax Credits |
State NOL Carryforwards |
Foreign NOL Carryforwards |
Total |
||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Balance as of December 31, 2004 |
$ | (112 | ) | $ | (23 | ) | $ | (1 | ) | $ | — | $ | (136 | ) | ||||||
| Acquisition of Sithe Energies |
(17 | ) | — | (15 | ) | — | (32 | ) | ||||||||||||
| Changes in valuation allowance—continuing operations |
(14 | ) | — | (1 | ) | (13 | ) | (28 | ) | |||||||||||
| Changes in valuation allowance—discontinued operations |
126 | — | — | — | 126 | |||||||||||||||
| Balance as of December 31, 2005 |
(17 | ) | (23 | ) | (17 | ) | (13 | ) | (70 | ) | ||||||||||
| Changes in valuation allowance—Sithe subordinated debt exchange |
— | — | 5 | — | 5 | |||||||||||||||
| Changes in valuation allowance—continuing operations |
— | — | (10 | ) | 13 | 3 | ||||||||||||||
| Changes in valuation allowance—discontinued operations |
— | — | (7 | ) | — | (7 | ) | |||||||||||||
| Balance as of December 31, 2006 |
(17 | ) | (23 | ) | (29 | ) | — | (69 | ) | |||||||||||
| Changes in valuation allowance—continuing operations |
— | — | 6 | — | 6 | |||||||||||||||
| Changes in valuation allowance—discontinued operations |
— | (1 | ) | 2 | — | 1 | ||||||||||||||
| Balance as of December 31, 2007 |
$ | (17 | ) | $ | (24 | ) | $ | (21 | ) | $ | — | $ | (62 | ) | ||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The changes in the valuation allowance by attribute for DHI were as follows:
| Capital Loss Carryforwards |
Foreign Tax Credits |
State NOL Carryforwards |
Foreign NOL Carryforwards |
Total |
||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Balance as of December 31, 2004 |
$ | (34 | ) | $ | (34 | ) | $ | (1 | ) | $ | — | $ | (69 | ) | ||||||
| Acquisition of Sithe Energies |
(17 | ) | — | (15 | ) | — | (32 | ) | ||||||||||||
| Changes in valuation allowance—continuing operations |
— | — | (1 | ) | (13 | ) | (14 | ) | ||||||||||||
| Changes in valuation allowance—discontinued operations |
34 | 29 | — | — | 63 | |||||||||||||||
| Balance as of December 31, 2005 |
(17 | ) | (5 | ) | (17 | ) | (13 | ) | (52 | ) | ||||||||||
| Changes in valuation allowance—Sithe subordinated debt exchange |
— | — | 5 | — | 5 | |||||||||||||||
| Changes in valuation allowance—continuing operations |
— | (15 | ) | (10 | ) | 13 | (12 | ) | ||||||||||||
| Changes in valuation allowance—discontinued operations |
— | — | (7 | ) | — | (7 | ) | |||||||||||||
| Balance as of December 31, 2006 |
(17 | ) | (20 | ) | (29 | ) | — | (66 | ) | |||||||||||
| Changes in valuation allowance—continuing operations |
— | — | 6 | — | 6 | |||||||||||||||
| Changes in valuation allowance—discontinued operations |
— | (1 | ) | 2 | — | 1 | ||||||||||||||
| Balance as of December 31, 2007 |
$ | (17 | ) | $ | (21 | ) | $ | (21 | ) | $ | — | $ | (59 | ) | ||||||
Acquisition of LS Power and Sithe Energies. On April 2, 2007, Dynegy acquired the Contributed Entities. Please read Note 3—Business Combinations and Acquisitions—LS Power Business Combination for further discussion. As a part of this transaction, Dynegy recorded a net deferred tax liability of $627 million. On January 31, 2005, we acquired 100 percent of the outstanding common shares of ExRes, the parent company of Sithe Energies and Independence. Please read Note 3—Business Combinations and Acquisitions—Sithe Energies Business Combination for further discussion. As a part of this transaction, we recorded a net deferred tax liability of $193 million.
Sithe Subordinated Debt Exchange. In July 2006, we acquired approximately $419 million principal amount of the subordinated debt of Sithe Independence, together with all claims for accrued and unpaid interest, in exchange for approximately $297 million principal amount of DHI’s 8.375 percent Senior Unsecured Notes. The acquisition produced a tax gain of approximately $129 million and increased the amount of state NOL carryforwards that can be utilized to reduce our state tax liability. The increased projected utilization reduced the amount of the state NOL valuation allowance by approximately $5 million. The release of the valuation allowance was applied against noncurrent intangible assets on a prospective basis and therefore did not impact current year earnings. Please read Note 15—Debt—Sithe Senior Notes for further discussion.
Unrecognized Tax Benefits. Dynegy files a consolidated income tax return in the U.S. federal jurisdiction, and we file other income tax returns in various states and foreign jurisdictions. DHI is included in Dynegy’s consolidated federal tax returns. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2004. Our federal income tax returns are routinely audited by the IRS, and provisions are routinely made in the financial statements in anticipation of the results of these audits. We have closed the IRS audit of our 2001-2002 tax years, and have received the Revenue Agent’s Report for our 2004-2005 tax years. We have also closed a CRA audit of our 2002-2004 tax years. As a
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
result of the IRS Revenue Agent’s Report, the Canadian audit settlement, and various state settlements, we recorded an expense, which is included in our income tax expense, of $8 million and $40 million for the years ended December 31, 2007 and 2006, respectively.
Dynegy adopted the provisions of FIN No. 48 on January 1, 2007 and recorded a decrease of $7 million to its accumulated deficit as of January 1, 2007 to reflect the cumulative effect of adopting FIN No. 48. DHI adopted the provisions of FIN No. 48 on January 1, 2007 and recorded a decrease of $13 million to its accumulated deficit as of January 1, 2007 to reflect the cumulative effect of adopting FIN No. 48. Additionally, in conjunction with the adoption of FIN No. 48, as of January 1, 2007, Dynegy reduced its regular federal tax NOL carryforwards by $253 million, from $948 million to $695 million. The reduction was offset by corresponding changes to its net deferred tax liability and reserve for uncertain tax positions. DHI reduced its regular federal tax NOL carryforwards by $153 million, from $597 million to $444 million. The reduction was offset by corresponding changes to its net deferred tax liability and reserve for uncertain tax positions.
A reconciliation of Dynegy’s and DHI’s beginning and ending amounts of unrecognized tax benefits follows:
| Dynegy |
DHI |
|||||||
| (in millions) | ||||||||
| Balance at January 1, 2007 |
$ | 111 | $ | 77 | ||||
| Additions based on tax positions related to the current year |
1 | 1 | ||||||
| Additions based on tax positions related to the prior year |
11 | 1 | ||||||
| Reductions based on tax positions related to the prior year |
(47 | ) | (46 | ) | ||||
| Settlements |
(43 | ) | (25 | ) | ||||
| Balance at December 31, 2007 |
$ | 33 | $ | 8 | ||||
As of December 31, 2007 and January 1, 2007, approximately $31 million and $67 million of unrecognized tax benefits would impact Dynegy’s effective tax rate if recognized. As of December 31, 2007 and January 1, 2007, approximately $6 million and $37 million of unrecognized tax benefits would impact DHI’s effective tax rate if recognized.
The changes to our unrecognized tax benefits during the twelve months ended December 31, 2007 primarily resulted from effective settlement of the IRS audit of our 2001-2002 tax years and the CRA audit of our 2002-2004 tax years. The adjustments to our reserves for uncertain tax positions as a result of these settlements had an insignificant impact on our net income.
Included in our balance of unrecognized tax benefits at December 31, 2007 is $2 million of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authorities to an earlier period.
During the years ended December 31, 2007 and 2006, we recognized less than $1 million and approximately $1 million in interest and penalties, respectively. Dynegy had approximately $(1) million and $5 million accrued for the payment of interest and penalties at December 31, 2007 and January 1, 2007, respectively. DHI had approximately $(1) million and $6 million accrued for the payment of interest and penalties at December 31, 2007 and January 1, 2007, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
We expect that our unrecognized tax benefits could continue to change due to the settlement of audits and the expiration of statutes of limitation in the next twelve months; however, we do not anticipate any such change to have a significant impact on our results of operations, financial position or cash flows in the next twelve months.
Note 18—Dynegy’s Earnings (Loss) Per Share
The reconciliation of basic earnings (loss) per share from continuing operations to diluted earnings (loss) per share from continuing operations of Dynegy common stock outstanding during the period is shown in the following table. Diluted earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of Dynegy common stock outstanding during the period plus each share that would have been outstanding assuming the issuance of common shares for all dilutive potential common shares outstanding during the period.
| Year Ended December 31, |
|||||||||||
| 2007 |
2006 |
2005 |
|||||||||
| (in millions, except per share amounts) | |||||||||||
| Income (loss) from continuing operations |
$ | 116 | $ | (321 | ) | $ | (800 | ) | |||
| Convertible preferred stock dividends |
— | (9 | ) | (22 | ) | ||||||
| Income (loss) from continuing operations for basic earnings (loss) per share |
116 | (330 | ) | (822 | ) | ||||||
| Effect of dilutive securities: |
|||||||||||
| Interest on convertible subordinated debentures |
— | 3 | 7 | ||||||||
| Dividends on Series C convertible preferred stock |
— | 9 | 22 | ||||||||
| Income (loss) from continuing operations for diluted earnings (loss) per share |
$ | 116 | $ | (318 | ) | $ | (793 | ) | |||
| Basic weighted-average shares |
750 | 459 | 387 | ||||||||
| Effect of dilutive securities: |
|||||||||||
| Stock options |
2 | 2 | 2 | ||||||||
| Convertible subordinated debentures |
— | 20 | 55 | ||||||||
| Series C convertible preferred stock |
— | 28 | 69 | ||||||||
| Diluted weighted-average shares |
752 | 509 | 513 | ||||||||
| Earnings (loss) per share from continuing operations: |
|||||||||||
| Basic |
$ | 0.15 | $ | (0.72 | ) | $ | (2.12 | ) | |||
| Diluted (1) |
$ | 0.15 | $ | (0.72 | ) | $ | (2.12 | ) | |||
| (1) | When an entity has a net loss from continuing operations adjusted for preferred dividends, SFAS No. 128, “Earnings per Share”, prohibits the inclusion of potential common shares in the computation of diluted per-share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the years ended December 31, 2006 and 2005. |
Note 19—Commitments and Contingencies
Legal Proceedings
Set forth below is a summary of our material ongoing legal proceedings. In accordance with SFAS No. 5, we record reserves for contingencies when information available indicates that a loss is probable and the amount
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
of the loss is reasonably estimable. In addition, we disclose matters for which management believes a material loss is at least reasonably possible. In all instances, management has assessed the matters below based on current information and made a judgment concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may prove materially inaccurate and such judgment is made subject to the known uncertainty of litigation.
Gas Index Pricing Litigation. We, several of our affiliates, our former joint venture affiliate West Coast Power and other energy companies were named defendants in twenty-two lawsuits in state and federal court claiming damages resulting from alleged price manipulation and false reporting of natural gas prices to various index publications in the 2000-2002 timeframe. The cases are pending in California, Nevada and Tennessee. Recent developments include:
| • | In October 2007, we, on behalf of ourselves and our former joint venture affiliate West Coast Power, entered into a confidential memorandum of understanding to settle the fourteen cases comprising the California-based gas index litigation. In February 2008, a formal settlement agreement was executed and funding occurred shortly thereafter. The settlement is without admission of wrongdoing, and we continue to deny plaintiffs’ allegations. |
| • | In November 2007, the Tennessee Appellate Court heard argument on plaintiffs’ appeal of the lower court’s dismissal. A decision is expected in the first quarter 2008. |
| • | The remaining six cases, three of which seek class certification, are pending in the United States District Court in Las Vegas, Nevada. Five of the cases were transferred through the multi-district litigation process from other states, including Kansas, Colorado, Wisconsin, Missouri and Illinois. All of the cases contain similar claims, that individually and in conjunction with other energy companies, we engaged in an illegal scheme to inflate natural gas prices by providing false information to natural gas index publications. The complaints rely heavily on prior FERC and Commodity Futures Trading Commission investigations into and reports concerning index manipulation in the energy industry. The lawsuits seek actual and punitive damages, restitution and/or expenses. In February 2008, the district court granted defendants’ motion for summary judgement in a Colorado class action which had also been transferred to Nevada, thereby dismissing the case and all of plaintiffs’ claims. |
During the twelve months ended December 31, 2007 and 2006, we recorded legal and settlement charges of approximately $16 million and $25 million, respectively, in general and administrative expenses in our consolidated statement of operations as a result of the actions noted above and in previous disclosures. We continue to analyze the Gas Index Pricing Litigation and are vigorously defending the remaining individual matters. Due to the uncertainty of litigation, we cannot predict whether we will incur any liability in connection with these lawsuits. However, given the nature of the claims, an adverse result in these proceedings could have a material adverse effect on our financial condition, results of operations and cash flows.
California Market Litigation. We and various other power generators and marketers were defendants in numerous lawsuits alleging rate and market manipulation in California’s wholesale electricity market during the California energy crisis several years ago. The complaints generally alleged unfair, unlawful and deceptive trade practices in violation of the California Unfair Business Practices Act and sought injunctive relief, restitution and unspecified actual and treble damages. All of these cases have been dismissed on grounds of federal preemption and affirmed on appeal. Plaintiffs in one case, which was dismissed by the district court and recently affirmed by the Ninth Circuit, sought rehearing by the appellate court. In January 2008, the Ninth Circuit denied plaintiffs’ motion. No California Market Litigation matters remain pending, however plaintiffs in the recently active matter have not fully exhausted their appellate review.
Nevada Power Arbitration. Through one of our indirect subsidiaries, we hold an ownership interest in Black Mountain, in which our equal partner is a CUSA subsidiary. Black Mountain has a long-term power sale
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DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
agreement with Nevada Power Company (“Nevada Power”) that extends through April 2023. In October 2007, Nevada Power initiated an arbitration against Black Mountain seeking a declaratory judgment that (i) Nevada Power’s methodology for calculating certain cumulative excess payments in the event of default or early termination by Black Mountain is correct and (ii) Black Mountain is obligated to repay to Nevada Power the full amount of any outstanding excess payments in the event of a default or early termination or upon the expiration of the agreement’s term in 2023. The arbitration is scheduled for July 2008 and the parties are actively engaged in discovery. Currently, Nevada Power does not allege an event of default or early termination has occurred. Nonetheless, Nevada Power maintains that as of December 31, 2007, if an event of default occurred, Black Mountain would be required to pay approximately $136 million in cumulative excess payments, 50 percent of which would be our proportionate share. We previously disclosed that we agreed to guarantee 50 percent of any Black Mountain obligation to pay cumulative excess payments. Nevada Power further alleges that the cumulative excess payments calculation could equal approximately $365 million in 2023 and would be payable upon the scheduled termination of the power sale agreement, 50 percent of which would be our proportionate share. Management does not believe that Black Mountain has an obligation to pay any amount to Nevada Power upon the scheduled termination of the agreement. We believe Nevada Power’s claims are without merit and we intend to defend against them vigorously. However, given the amount in controversy, an adverse ruling could have a material adverse effect on our future financial condition, results of operations and cash flows.
Illinois Auction Complaints. In March 2007, the Attorney General of the State of Illinois (the “IAG”) filed a complaint at FERC (the “IAG FERC Complaint”) against sixteen electricity suppliers engaged in wholesale power sales, challenging the results of the Illinois reverse power procurement auction conducted in September 2006. In July 2007, the IAG filed a motion to suspend its complaint at FERC and legislative leaders from the State of Illinois announced a comprehensive transitional rate relief package for electric consumers. Adoption of legislation incorporating the rate relief package and related agreements resulted in the dismissal of the IAG FERC Complaint in October 2007.
In connection with the rate relief legislation, we agreed to 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 2007, have begun making monthly payments that will total $9.0 million in 2008, and anticipate making payments totaling $8.5 million in 2009. We recorded a $25 million expense in 2007 related to these payments, which is included in cost of sales on our consolidated statement of operations. Our payment of $7.5 million in September 2007 is to be used for funding of the Illinois Power Agency, which is to be created as part of Illinois’ comprehensive rate relief legislation. Our expected payments for 2008 and 2009 will be made in monthly installments so long as Illinois does not impose an electric rate freeze or an additional tax on generators prior to December 2009, as further described in the rate relief legislation and related agreements. The monthly payments will be paid into an escrow account established to support rate relief activities for Ameren Illinois Utilities’ customers.
The rate relief legislation and related agreements resulted in motions to dismiss with prejudice being filed in several ongoing court and regulatory proceedings including the IAG FERC Complaint, appeals of the original orders adopting the auction process and the auction improvements case. These dismissals have been entered by the respective agencies and courts.
In March 2007, two civil class action complaints were filed in Illinois state court against twenty-one wholesale electricity suppliers and utilities, including DPM, seeking unspecified actual and punitive damages. The complaints largely mirrored the IAG FERC Complaint challenging the results of the Illinois reverse power procurement auction conducted in September 2006. In April 2007, the cases were removed to federal court, and in June 2007, the defendants moved to dismiss plaintiffs’ claims on grounds of the filed rate doctrine and preemption. In December 2007, the district court dismissed all of plaintiffs’ claims.
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New York Attorney General Subpoena. On September 17, 2007, Dynegy and four other companies received a subpoena from the Office of the New York Attorney General The subpoena seeks information and documents related to, among other things: Dynegy’s evaluation, analysis and projections regarding climate change; the impact of climate change on Dynegy’s operations; development opportunities through Dynegy’s joint venture with LS Power; and alleged deficiencies in Dynegy’s SEC disclosures related to the foregoing. We are reviewing the subpoena and discussing its contents with the New York Attorney General’s office in anticipation of our responding as appropriate.
Illinova Arbitration. In June 2000, Dynegy’s subsidiary, Illinova Generating Company (“IGC”), sold a minority interest it held in a Cleburne, Texas generating plant to Ponderosa Pine Energy (“PPE”). Brazos Electric Cooperative, Inc. (“Brazos”), the party to an offtake agreement from the plant, brought legal action against PPE alleging that PPE’s purchase did not comply with the terms of Brazos’ offtake agreement. Brazos received a favorable arbitration award against PPE, which in turn sought recovery from IGC and the other former owners of the plant for indemnification. In May 2007, the panel in PPE’s arbitration action ruled that IGC and the other former owners of the plant must indemnify PPE for the Brazos arbitration award, with IGC’s portion being defined as approximately $17 million. Dynegy recognized a legal settlement charge of approximately $17 million in the first quarter 2007 relating to this adverse ruling. In May 2007, Dynegy paid the judgment under protest. PPE moved to enforce the arbitration award in state district court and the defendants have filed a motion to vacate the arbitration award. A hearing on these motions was held in December 2007, with a ruling expected in the first quarter 2008.
Bridgeport RMR Agreement. The Bridgeport facility had been operating pursuant to the terms of a reliability-must-run (“RMR”) agreement, subject to the outcome of ongoing proceedings before FERC to resolve the question of whether Bridgeport is eligible for an RMR agreement. On May 25, 2007, Bridgeport and the intervening parties submitted a Joint Offer of Settlement (the “Settlement”), which effectively terminated the RMR Agreement as of May 31, 2007. In addition, the Settlement stipulated that within 30 days of FERC approval, Bridgeport would refund ISO New England (“ISO-NE”) $12.5 million and any RMR revenues received by Bridgeport from the ISO-NE under the amended RMR agreement for the calendar months April 2007 and May 2007. We recorded a reserve of $12.5 million payable to the ISO-NE as part of the LS Power purchase price allocation, and reserved any RMR revenues received from the ISO-NE for April and May 2007. Under the Settlement, as of June 1, 2007, Bridgeport is no longer required to submit stipulated bids, which allows Bridgeport to more fully participate as a merchant generator in the ISO-NE market. We funded the payments to ISO-NE in late August 2007.
Danskammer State Pollutant Discharge Elimination System Permit. In January 2005, the New York State Department of Environmental Conservation (“NYSDEC”) issued a Draft Danskammer SPDES Permit renewal for the Danskammer plant, and an adjudicatory hearing was scheduled for the fall of 2005. Three environmental groups sought to impose a permit requirement that the Danskammer plant install a closed cycle cooling system in order to reduce the volume of water withdrawn from the Hudson River, thus reducing aquatic organism mortality. The petitioners claim that only a closed cycle cooling system meets the Clean Water Act’s requirement that the cooling water intake structures reflect best technology available (“BTA”) for minimizing adverse environmental impacts.
A formal evidentiary hearing was held in November and December 2005. The Deputy Commissioner’s decision directing that the NYSDEC staff issue the revised Draft Danskammer SPDES Permit was issued in May 2006. In June 2006, the NYSDEC issued the revised Danskammer SPDES Permit with conditions generally favorable to us. While the revised Danskammer SPDES Permit does not require installation of a closed cycle cooling system, it does require aquatic organism mortality reductions resulting from NYSDEC’s determination of
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DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
BTA requirements under its regulations. In July 2006, two of the petitioners filed suit in the Supreme Court of the State of New York seeking to vacate the Deputy Commissioner’s decision and the revised Danskammer SPDES Permit. On March 26, 2007, the Court transferred the lawsuit to the Third Department Appellate Division. The case will now proceed as a normal appeal from a final agency decision and the decision will be based on whether there is substantial evidence in the record to support the agency decision. On December 21, 2007, petitioners filed their Brief for Appellants. Our Respondent’s Brief will be filed by March 19, 2008 and we expect a decision in the summer of 2008. We believe that the decision of the Deputy Commissioner is well reasoned and will be affirmed. However, in the event the decision is not affirmed and we ultimately are required to install a closed cycle cooling system, this could have a material adverse effect on our financial condition, results of operations and cash flows.
Roseton State Pollutant Discharge Elimination System Permit. In April 2005, the NYSDEC issued a Draft SPDES Permit renewal for the Roseton plant. The Draft Roseton SPDES Permit requires the facility to actively manage its water intake to substantially reduce mortality of aquatic organisms.
In July 2005, a public hearing was held to receive comments on the Draft Roseton SPDES Permit. Three environmental organizations filed petitions for party status in the permit renewal proceeding. The petitioners are seeking to impose a permit requirement that the Roseton plant install a closed cycle cooling system in order to reduce the volume of water withdrawn from the Hudson River, thus reducing aquatic organism mortality. The petitioners claim that only a closed cycle cooling system meets the Clean Water Act’s requirement that the cooling water intake structures reflect the BTA for minimizing adverse environmental impacts. In September 2006, the administrative law judge issued a ruling admitting the petitioners to full party status and setting forth the issues to be adjudicated in the permit renewal hearing. Various holdings in the ruling have been appealed to the Commissioner of NYSDEC by us, NYSDEC staff, and the petitioners. We expect that the adjudicatory hearing on the Draft Roseton SPDES Permit will occur in 2008. We believe that the petitioners’ claims are without merit, and we plan to oppose those claims vigorously. Given the high cost of installing a closed cycle cooling system, an adverse result in this proceeding could have a material adverse effect on our financial condition, results of operations and cash flows.
Moss Landing National Pollutant Discharge Elimination System Permit. The California Regional Water Quality Control Board (“Water Board”) issued a NPDES permit for the Moss Landing Power Plant in 2000 in connection with modernization of the plant and the California Energy Commission’s licensing of that project. A local environmental group sought review of the permit in Superior Court in Monterey County in July 2001 claiming that the permit was not supported by sufficient analysis of the BTA for cooling water intake structures as required under the Clean Water Act. Petitioner contends that the once-through, seawater-cooling system at Moss Landing should be replaced with a closed cycle cooling system.
The Superior Court concluded that the Water Board’s BTA analysis was insufficient and remanded the permit to the Water Board directing a comprehensive analysis and reconsideration of the NPDES permit. Following the hearing on remand, the Water Board affirmed its BTA finding. In July 2004, the Superior Court held that the Water Board had conducted a thorough and comprehensive BTA analysis on remand. This decision was appealed by petitioner to California’s Sixth Appellate District. On December 14, 2007, the Court of Appeals issued its opinion affirming the trial court’s judgment upholding the permit. A petition for rehearing was denied in January 2008. The petitioners filed a Petition for Review on January 23, 2008 seeking further review by the Supreme Court of California.
We believe that petitioner’s claims lack merit and we plan to oppose those claims vigorously. Given the high cost of installing a closed cycle cooling system, an adverse result in this proceeding could have a material adverse effect on our financial condition, results of operation and cash flow.
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Other. In addition to the matters discussed above, we are party to numerous legal proceedings arising in the ordinary course of business or related to discontinued business operations. In management’s judgment, which may prove to be materially inaccurate as indicated above, the disposition of these matters will not materially adversely affect our financial condition, results of operations or cash flows.
Other Commitments and Contingencies
In conducting our operations, we have routinely entered into long-term commodity purchase and sale commitments, as well as agreements that commit future cash flow to the lease or acquisition of assets used in our businesses. These commitments have been typically associated with commodity supply arrangements, capital projects, reservation charges associated with firm transmission, transportation, storage and leases for office space, equipment, plant sites, power generation assets and LPG vessel charters. The following describes the more significant commitments outstanding at December 31, 2007.
Purchase Obligations. We have firm capacity payments related to transportation of natural gas. Such arrangements are routinely used in the physical movement and storage of energy. The total of such obligations was $396 million as of December 31, 2007.
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 through the term of the contract.
Midwest Consent Decree. 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 install emission control equipment at our Baldwin, Vermilion, Hennepin and Havana power generating facilities. We have spent approximately $90 million to date related to these consent decree projects and anticipate incurring significantly more costs over the course of the next five years in connection with the consent decree.
Other Minimum Commitments. 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 power generating facility. The Vermilion facility is included in the GEN-MW segment. 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. Minimum commitments at December 31, 2007 were $2 million for each of the years ending 2008, 2009, 2010, 2011 and 2012 and a total of $4 million thereafter.
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In the first quarter 2001, we acquired the Roseton and Danskammer power generation facilities. In May 2001, two of our subsidiaries completed a sale-leaseback transaction to provide term financing for these facilities. Under the terms of the sale-leaseback transaction, our subsidiaries sold plants and equipment and agreed to lease them back for terms expiring within 34 years, exclusive of renewal options. We have no option to purchase the leased facilities at the end of their respective lease terms. If one or more of the leases were to be terminated because of an event of loss, because it becomes illegal for the applicable lessee to comply with the lease or because a change in law makes the facility economically or technologically obsolete, DHI would be required to make a termination payment. As of December 31, 2007, the termination payment would be approximately $1 billion for these facilities.
Minimum commitments in connection with office space, equipment, plant sites and other leased assets, including the leases discussed above, at December 31, 2007, were as follows: 2008—$144 million, 2009—$141 million, 2010—$95 million, 2011—$112 million, 2012—$179 million and beyond—$533 million.
Rental payments made under the terms of these arrangements totaled $122 million in 2007, $80 million in 2006 and $88 million in 2005.
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 for each year from 2008 through 2012, and approximately $8 million for 2013 through lease expiration. The charter party rates payable under the two charter party agreements float in accordance with market based rates for similar shipping services. The $14 million and $8 million amounts set forth above are based on the minimum obligations set forth in the two charter party agreements. The primary term of one charter is through August 2013 while the primary term of the second charter is through August 2014. 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. To date, the subsidiary of Transammonia has complied with the terms of the sub-charter agreements.
Regulatory Matters
We are subject to regulation by various federal, state and local agencies, including extensive rules and regulations governing transportation, transmission and sale of energy commodities as well as the discharge of materials into the environment or otherwise relating to environmental protection. Compliance with these regulations requires general and administrative, capital and operating expenditures including those related to monitoring, pollution control equipment, emission fees and permitting at various operating facilities and remediation obligations.
Illinois Resource Procurement Auction. 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 Corporation 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. Please read “—Commitments and Contingencies—Legal proceedings—Illinois Auction Complaints” for further discussion.
Mercury Emissions. In December 2006, the Illinois Pollution Control Board approved a state rule for the control of mercury emissions from coal-fired power plants that required additional capital and O&M expenditures at each of our Illinois coal-fired plants beginning in 2007. In January 2007, the State of New York also approved a mercury rule that will likely require additional capital and operating costs at our Danskammer plant.
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FERC Market-Based Rate Authority. FERC’s market-based rate authority allows the sale of power at negotiated rates through the bilateral market or within an organized energy market, conditioned on periodic re-review. In June 2007, the FERC finalized a series of fundamental reforms to its market-based rate program intended to strengthen competitive markets and protect consumers by reinforcing regulations for just and reasonable wholesale electric power sales by protecting consumers from an electric power seller’s exercise of market power. Our next triennial market power analysis is due June 16, 2008.
Guarantees and Indemnifications
In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be remote. Related to the indemnifications discussed below, we have accrued approximately $9 million as of December 31, 2007.
West Coast Power Indemnities. In connection with the sale of our 50 percent interest in West Coast Power to NRG on March 31, 2006, an agreement was executed to allocate responsibility for managing certain litigation and provide for certain indemnities with respect to such litigation. The agreement states that we will manage the Gas Index Pricing Litigation described above for which NRG could suffer a loss subsequent to the closing and that we would indemnify NRG for all costs or losses resulting from such litigation, as well as from other proceedings based on similar acts or omissions, which formed the basis of such litigation. Upon execution of the California Gas Index Pricing Litigation settlement discussed above, West Coast Power will no longer be a party to any active Gas Index Pricing Litigation matters subject to this indemnity. The agreement further states that we will manage the California Market Litigation described above for which NRG could suffer a loss subsequent to the closing, and that we and NRG would each be responsible for 50 percent of any costs or losses resulting from that power litigation, as well as from other proceedings based on similar acts or omissions which formed the basis of such litigation. The agreement provides that NRG will manage other active litigation and indemnify us for any resulting losses, subject to certain conditions. Maximum recourse under these matters is not limited by the agreement or by the passage of time with the exception of the California Department of Water Resources matter in which NRG has a specified indemnity obligation. The damages claimed by the various plaintiffs in these matters are unspecified as of December 31, 2007.
Targa Indemnities. During 2005, as part of our sale of DMSLP, we agreed to indemnify Targa against losses it may incur under indemnifications DMSLP provided to purchasers of certain assets, properties and businesses disposed of by DMSLP prior to our sale of DMSLP. We have incurred no significant expense under these prior indemnities and deem their value to be insignificant. We have recorded an accrual in association with the cleanup of groundwater contamination at the Breckenridge Gas Processing Plant. The indemnification provided by DMSLP to the purchaser of the plant has a limit of $5 million. We have also indemnified Targa for certain tax matters arising from periods prior to our sale of DMSLP. We have recorded a reserve associated with this indemnification.
Illinois Power Indemnities. As a condition of Dynegy’s 2004 sale of Illinois Power and its interest in Electric Energy Inc.’s plant in Joppa, Illinois, Dynegy provided indemnifications to third parties regarding
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environmental, tax, employee and other representations. These indemnifications are limited to a maximum recourse of $400 million. Additionally, Dynegy has indemnified third parties against losses resulting from possible adverse regulatory actions taken by the ICC that could prevent Illinois Power from recovering costs incurred in connection with purchased natural gas and investments in specified items. Although there is no limitation on Dynegy’s liability under this indemnity, the amount of the indemnity is limited to 50 percent of any such losses. In July 2005, Dynegy made a payment of $8 million to Ameren in settlement of Ameren’s indemnification claims with respect to an ICC Order disallowing items relating to one of Illinois Power’s natural gas storage fields resulting in a negative revenue requirement impact to Ameren. In anticipation of similar cases, Dynegy recognized a pre-tax charge of $12 million in 2005. As anticipated, Dynegy paid Ameren for an additional amount disallowed in a similar ICC Order in the third quarter 2006. Furthermore, in August 2007, the ICC issued its final Order in another of the related cases, which has been appealed. Dynegy has adjusted the amount reserved for the various ongoing cases in light of these and other developments in the cases. Further disallowances and other events, which fall within the scope of the indemnity, may still occur; however, Dynegy is not required to accrue a liability in connection with these indemnifications, as management cannot reasonably estimate a range of outcomes or at this time considers the probability of an adverse outcome as only reasonably possible. Dynegy intends to contest any proposed disallowances.
Northern Natural and Other Indemnities. During 2003, as part of our sales of Northern Natural, the Rough and Hornsea natural gas storage facilities and certain natural gas liquids assets, we provided indemnities to third parties regarding environmental, tax, employee and other representations. Maximum recourse under these indemnities is limited to $209 million, $857 million and $28 million, respectively. We also entered into similar indemnifications regarding environmental, tax, employee and other representations when completing other asset sales such as, but not limited to CoGen Lyondell, Rockingham, Hackberry LNG Project, SouthStar Energy Services, various Canadian assets, Michigan Power, Oyster Creek, Hartwell, Commonwealth, Sherman, and Indian Basin. We have recorded reserves for existing environmental, tax and employee liabilities and have incurred no other expense relating to these indemnities.
Note 20—Capital Stock
At December 31, 2007, Dynegy had authorized capital stock consisting of 2,100,000,000 shares of Class A common stock, $0.01 par value per share and 850,000,000 shares of Class B common stock, $0.01 par value per share.
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.
Preferred Stock. Dynegy has authorized preferred stock consisting of 100,000,000 shares, $0.01 par value. Dynegy preferred stock may be issued from time to time in one or more series, the shares of each series to have such designations and powers, preferences, rights, qualifications, limitations and restrictions thereof as specified by Dynegy’s Board of Directors.
Common Stock. At December 31, 2007, there were 842,819,794 shares of Dynegy Class A and B common stock issued in the aggregate and 2,449,259 shares were held in treasury. During 2007 and 2006, no quarterly cash dividends were paid by Dynegy.
Pursuant to the terms of the Merger Agreement, Dynegy established two classes of common shares, Class A and Class B. All of Dynegy’s outstanding Class B common stock is owned by the LS Contributing Entities and its permitted transferees, affiliates and associates (the “LS Control Group”). Generally, holders of Class B
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common stock vote together with the holders of Class A common stock as a single class on every matter acted upon by the stockholders except for the following matters:
| • | the holders of Class B common stock vote as a separate class for the election of up to three of Dynegy’s directors, while the holders of Class A common stock vote as a separate class for the remaining directors; |
| • | any amendment to the provisions of Dynegy’s Certificate of Incorporation addressing the voting rights of holders of Class A and Class B common stock or to Section 7 of Article III or Article X of its Bylaws requires the affirmative vote of a majority of the outstanding shares of Class B common stock voting as a separate class, and the affirmative vote of a majority of the shares of common stock, voting together as a single class, except that no such stockholder approval is required with respect to an amendment to Section 7 of Article III or Article X of Dynegy’s Bylaws if such amendment is approved by a majority of the Class B Directors present at a meeting where such amendment is considered and by a majority of all Dynegy directors; and |
| • | any agreement of merger or consolidation if a party to such agreement is a member of the LS Control Group or an affiliate of such group requires the affirmative vote of a majority of the shares of Class A common stock outstanding, voting as a separate class, and the affirmative vote of a majority of all shares of common stock outstanding, voting together as a single class. |
Holders of Class A and Class B common stock are entitled to one vote per share on all matters submitted to a vote of stockholders. Holders of common stock will not be entitled to cumulative voting. The voting rights of any holders of common stock will be subject to the voting rights of holders of any series of preferred stock that may be issued from time to time.
Subject to the preferences of preferred stock, holders of Class A and Class B common stock have equal and ratable rights to dividends, when and if dividends are declared by the Board of Directors. Holders of Class A and Class B common stock are entitled to share ratably, as a single class, in all of Dynegy’s assets available for distribution to holders of shares of common stock upon the liquidation, dissolution or winding up of Dynegy’s affairs, after payment of Dynegy’s liabilities and any amounts to holders of preferred stock, if any.
A share of Class B common stock automatically converts into a share of Class A common stock if it is transferred to any person other than a member of the LS Control Group. Additionally, each share of Class B common stock automatically converts into a share of Class A common stock when the outstanding shares of Class B common stock represent less than 10 percent of the total outstanding shares of Dynegy’s common stock. As long as the outstanding shares of Class B common stock represent at least 10 percent of the total outstanding shares, each share of Class A common stock owned by the LS Control Group will automatically be converted into one share of Class B common stock.
Holders of Class A and Class B common stock generally are not entitled to preemptive rights, subscription rights, or redemption rights, except that the LS Control Group is entitled to preemptive rights under the shareholder agreement. The rights and preferences of holders of common stock are subject to the rights of any series of preferred stock we may issue.
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Common stock activity for the three years ended December 31, 2007 was as follows:
| Class A Common Stock |
Class B Common Stock held by CUSA |
Class B Common Stock held by LS Power | ||||||||||||||||
| Shares |
Amount |
Shares |
Amount |
Shares |
Amount | |||||||||||||
| (in millions) | ||||||||||||||||||
| December 31, 2004 |
285 | $ | 2,859 | 97 | $ | 1,006 | — | $ | — | |||||||||
| Options exercised |
1 | 4 | — | — | — | — | ||||||||||||
| 401(k) plan and profit sharing |
1 | 5 | — | — | — | — | ||||||||||||
| Shareholder litigation settlement |
18 | 81 | — | — | — | — | ||||||||||||
| December 31, 2005 |
305 | $ | 2,949 | 97 | $ | 1,006 | — | $ | — | |||||||||
| Options exercised |
3 | 5 | — | — | — | — | ||||||||||||
| 401(k) plan and profit sharing |
1 | 3 | — | — | — | — | ||||||||||||
| Equity issuance |
40 | 185 | — | — | ||||||||||||||
| Equity conversion |
54 | 225 | — | — | — | — | ||||||||||||
| December 31, 2006 |
403 | $ | 3,367 | 97 | $ | 1,006 | — | $ | — | |||||||||
| Options exercised |
2 | 1 | — | — | — | — | ||||||||||||
| 401(k) plan and profit sharing |
1 | 1 | — | — | — | — | ||||||||||||
| LS Power Business Combination: |
||||||||||||||||||
| Conversion of Chevron Class B shares to Class A shares |
97 | 1,006 | (97 | ) | (1,006 | ) | — | — | ||||||||||
| Conversion from Illinois entity to Delaware entity |
— | (4,370 | ) | — | — | — | — | |||||||||||
| Issuance of LS Power Class B shares |
— | — | — | — | 340 | 3 | ||||||||||||
| December 31, 2007 |
503 | $ | 5 | — | $ | — | 340 | $ | 3 | |||||||||
Treasury Stock. During 2007, 2006 and 2005, Class A common shares purchased into treasury totaled 662,255, 72,978 and 34,843, respectively. All of the purchases were related to forfeitures of restricted stock and shares withheld to satisfy income tax withholding requirements in connection with the vesting of restricted stock awards.
Stock Award Plans. Dynegy has nine stock option plans, all of which provide for the issuance of authorized shares of Dynegy’s Class A common stock. Restricted stock awards and option grants are issued under the plans. Each option granted is exercisable at a strike price, which ranges from $1.47 per share to $56.98 per share for options currently outstanding. A brief description of each plan is provided below:
| • | NGC Plan. Created early in Dynegy’s history and revised prior to Dynegy becoming a publicly traded company in 1996, this plan provided for the issuance of 13,651,802 authorized shares, had a 10-year term, and expired in May 2006. All option grants are vested. |
| • | Employee Equity Plan. This plan is the only plan under which Dynegy granted options below the fair market value of its Class A common stock on the date of grant. This plan provided for the issuance of 20,358,802 authorized shares and expired in May 2002. Grants under this plan vested on the fifth anniversary from the date of the grant. All option grants are vested. |
| • | Illinova Plan. Adopted by Illinova prior to the merger with Dynegy, this plan provided for the issuance of 3,000,000 authorized shares and expired upon the merger date in February 2000. All option grants are vested. |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| • | Extant Plan. Adopted by Extant prior to its acquisition by Dynegy, this plan provided for the issuance of 202,577 authorized shares and expired in September 2000. Grants from this plan vested at 25 percent per year. All option grants are vested. |
| • | UK Plan. This plan provided for the issuance of 276,000 authorized shares and has been terminated. All option grants are vested. |
| • | Dynegy 1999 Long-Term Incentive Plan (“LTIP”). This annual compensation plan provides for the issuance of 6,900,000 authorized shares, has a 10-year term and expires in 2009. All option grants are vested. |
| • | Dynegy 2000 LTIP. This annual compensation plan, created for all employees upon Illinova’s merger with us, provides for the issuance of 10,000,000 authorized shares, has a 10-year term and expires in February 2010. Grants from this plan vest in equal annual installments over a three-year period. |
| • | Dynegy 2001 Non-Executive LTIP. This plan is a broad-based plan and provides for the issuance of 10,000,000 authorized shares, has a ten-year term and expires in September 2011. Grants from this plan vest in equal annual installments over a three-year period. |
| • | Dynegy 2002 LTIP. This annual compensation plan provides for the issuance of 10,000,000 authorized shares, has a 10-year term and expires in May 2012. Grants from this plan vest in equal annual installments over a three-year period. |
All options granted under Dynegy’s option plans cease vesting for employees who are terminated for cause. For voluntary and involuntary termination, disability, retirement or death, continued vesting and/or an extended period in which to exercise vested options may apply, dependent upon the terms of the grant agreement applying to a specific grant that was awarded. It has been Dynegy’s practice to issue shares of common stock upon exercise of stock options generally from previously unissued shares. Options awarded to Dynegy’s executive officers and others who participate in our Executive Severance Pay Plan vest immediately upon the occurrence of a change in control in accordance with the terms of the Second Supplemental Amendment to the Executive Severance Pay Plan.
The Merger constituted a change in control as defined in Dynegy’s severance pay plans, as well as the various grant agreements. Please read Note 3—Business Combinations and Acquisitions—LS Power Business Combination for further discussion of the transaction. As a result, all options previously granted to employees fully vested immediately upon the closing of the Merger and related change in control. This occurrence resulted in the accelerated vesting of the unvested tranche of previous option grants issued in 2006 and 2005, which did not have a material effect on Dynegy’s financial condition, results of operations or cash flows.
During 2006, Dynegy entered into an exchange transaction with its Chairman and CEO. Under the terms of the transaction, the purpose of which was to address uncertainties created by proposed regulations issued in late 2005 pursuant to Section 409A of the Internal Revenue Code, Dynegy cancelled all of the 2,378,605 stock options then held by its Chairman and CEO. As consideration for canceling these stock options, Dynegy granted its Chairman and CEO 967,707 stock options at an exercise price of $4.88, which equaled the closing price of its Class A common stock on the date of grant, and made a cash payment to him of approximately $5.6 million on January 15, 2007 based on the in-the-money value of the vested stock options that were cancelled. These stock options vested immediately upon the closing of the Merger and related change in control. Please read Note 3—Business Combinations and Acquisitions—LS Power Business Combination for further discussion. We were not required to record any incremental compensation expense in connection with the transaction.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Compensation expense related to options granted and restricted stock awarded totaled $19 million, $8 million and $9 million for the years ended December 31, 2007, 2006 and 2005, respectively. We recognize compensation expense ratably over the vesting period of the respective awards. Tax benefits for compensation expense related to options granted and restricted stock awarded totaled $8 million, $3 million and $3 million for the years ended December 31, 2007, 2006 and 2005, respectively. As of December 31, 2007, $14 million of total unrecognized compensation expense related to options granted and restricted stock awarded is expected to be recognized over a weighted-average period of 1.4 years. The total fair value of shares vested was $20 million, $4 million and $6 million for the years ended December 31, 2007, 2006 and 2005, respectively. We did not capitalize or use cash to settle any share-based compensation in the years ended December 31, 2007 or 2006, other than as described above.
Cash received from option exercises for the years ended December 31, 2007 and 2006 was $4 million and $5 million, and the tax benefit realized for the additional tax deduction from share-based payment awards totaled $4 million and $3 million, respectively. The total intrinsic value of options exercised and released for the years ended December 31, 2007, 2006 and 2005 was $23 million, $5 million and $1 million, respectively.
In 2007, we granted stock-based compensation awards that cliff vest after three years based on achievement of Dynegy’s stock price target on April 23, 2010. In 2006, we granted stock-based compensation awards that cliff vest after three years based on our cumulative operating cash flows for 2006-2008. Compensation expense recorded in the years ended December 31, 2007 and 2006 related to these “performance units” was $4 million and less than $1 million, respectively, and was accrued in Other long-term liabilities in our consolidated balance sheets. The Merger constituted a change in control as related to the 2006 performance units. Please read Note 3—Business Combinations and Acquisitions—LS Power Business Combination for further discussion.
Stock option activity for the years ended December 31, 2007, 2006 and 2005 was as follows:
| Year Ended December 31, | ||||||||||||||||||
| 2007 |
2006 |
2005 | ||||||||||||||||
| Options |
Weighted Average Exercise Price |
Options |
Weighted Average Exercise Price |
Options |
Weighted Average Exercise Price | |||||||||||||
| (options in thousands) | ||||||||||||||||||
| Outstanding at beginning of period |
7,361 | $ | 12.63 | 9,314 | $ | 12.66 | 10,233 | $ | 15.91 | |||||||||
| Granted |
2,136 | $ | 9.67 | 3,268 | $ | 4.88 | 2,056 | $ | 4.30 | |||||||||
| Exercised |
(872 | ) | $ | 4.29 | (1,560 | ) | $ | 3.46 | (633 | ) | $ | 3.44 | ||||||
| Cancelled or expired |
(205 | ) | $ | 18.60 | (3,661 | ) | $ | 9.68 | (2,342 | ) | $ | 22.15 | ||||||
| Outstanding at end of period |
8,420 | $ | 12.60 | 7,361 | $ | 12.63 | 9,314 | $ | 12.66 | |||||||||
| Vested and unvested expected to vest |
8,137 | $ | 12.70 | 6,898 | $ | 13.16 | — | $ | — | |||||||||
| Exercisable at end of period |
6,305 | $ | 13.59 | 3,774 | $ | 20.07 | 7,059 | $ | 15.94 | |||||||||
| Year Ended December 31, 2007 | |||||
| Weighted Average Remaining Contractual Life (in years) |
Aggregate Intrinsic Value (in millions) | ||||
| Outstanding at end of period |
6.15 | $ | 9.43 | ||
| Vested and unvested expected to vest |
6.05 | $ | 9.43 | ||
| Exercisable at end of period |
5.22 | $ | 9.43 | ||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
During the three-year period ended December 31, 2007, we did not grant any options at an exercise price less than the market price on the date of grant.
Options outstanding as of December 31, 2007 are summarized below:
| Options Outstanding |
Options Exercisable | |||||||||||
| Range of Exercise Prices |
Number of Options Outstanding at December 31, 2007 |
Weighted Average Remaining Contractual Life (Years) |
Weighted Average Exercise Price |
Number of Options Exercisable at December 31, 2007 |
Weighted Average Exercise Price | |||||||
| (options in thousands) | ||||||||||||
| $1.47-$4.48 |
983 | 5.40 | $ | 3.60 | 983 | $ | 3.60 | |||||
| $4.49-$4.88 |
2,632 | 7.93 | $ | 4.88 | 2,632 | $ | 4.88 | |||||
| $7.02-$8.70 |
21 | 4.99 | $ | 7.75 | 12 | $ | 7.02 | |||||
| $8.71-$9.67 |
2,098 | 8.90 | $ | 9.67 | — | $ | — | |||||
| $9.68-$16.62 |
996 | 1.46 | $ | 13.88 | 988 | $ | 13.91 | |||||
| $16.63-$23.85 |
980 | 3.31 | $ | 23.76 | 980 | $ | 23.76 | |||||
| $23.86-$48.01 |
690 | 2.98 | $ | 45.07 | 690 | $ | 45.07 | |||||
| $48.02-$50.63 |
3 | 2.79 | $ | 50.63 | 3 | $ | 50.63 | |||||
| $50.64-$52.50 |
5 | 2.70 | $ | 52.50 | 5 | $ | 52.50 | |||||
| $52.51-$56.98 |
12 | 1.38 | $ | 56.98 | 12 | $ | 56.98 | |||||
| 8,420 | 6,305 | |||||||||||
For stock options, we determine the fair value of each stock option at the grant date using a Black-Scholes model, with the following weighted-average assumptions used for grants.
| Year Ended December 31, |
|||||||||
| 2007 |
2006 |
2005 |
|||||||
| Dividends |
— | — | — | ||||||
| Expected volatility (historical) |
45.60 | % | 48.8 | % | 84.1 | % | |||
| Risk-free interest rate |
4.9 | % | 5.1 | % | 4.2 | % | |||
| Expected option life |
6 Years | 6 Years | 10 Years | ||||||
The expected volatility was calculated based on a ten-year historical volatility of our stock price in 2005; beginning in first quarter 2006, we used a three-year historical volatility. The risk-free interest rate was calculated based upon observed interest rates appropriate for the term of our employee stock options. Currently, we calculate the expected option life using the simplified methodology suggested by SAB 107, “Share-Based Payment”. For restricted stock awards, we consider the fair value to be the closing price of the stock on the grant date. We recognize the fair value of our share-based payments over the vesting periods of the awards, which is typically a three-year service period.
The weighted average grant-date fair value of options granted during the years ended December 31, 2007, 2006 and 2005 was $4.91, $2.61 and $3.66, respectively.
F-77
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Restricted stock activity for the three years ended December 31, 2007 was as follows:
| Year Ended December 31, |
||||||||||||
| 2007 |
2007 Weighted Average Grant Date Fair Value |
2006 |
2005 |
|||||||||
| Outstanding at beginning of period |
2,114 | $ | 4.67 | 1,239 | 902 | |||||||
| Granted |
1,643 | (1) | $ | 9.67 | 1,311 | (2) | 632 | (3) | ||||
| Vested |
(2,110 | ) | $ | 4.70 | (251 | ) | (130 | ) | ||||
| Cancelled or expired |
(92 | ) | $ | 8.83 | (185 | ) | (165 | ) | ||||
| Outstanding at end of period |
1,555 | $ | 9.67 | 2,114 | 1,239 | |||||||
| (1) | We awarded 1,639,088 shares, 1,967 shares and 2,299 shares of restricted stock in April 2007, May 2007 and September 2007, respectively. The closing stock prices were $9.67, $10.17 and $8.70, respectively, on the dates of the awards. |
| (2) | We awarded 1,311,149 shares of restricted stock in March 2006. The closing stock price was $4.88 on the date of the award. |
| (3) | We awarded 631,524 shares of restricted stock in January 2005. The closing stock price was $4.30 on the date of the award. |
All restricted stock awards to employees vest immediately upon the occurrence of a change in control in accordance with the terms of the applicable Severance Pay Plan. The Merger constituted a change in control as defined in our restricted stock agreements. Please read Note 3—Business Combinations and Acquisitions—LS Power Business Combination for further discussion.
Note 21—Employee Compensation, Savings and Pension Plans
Short-Term Incentive Plan. We maintain a discretionary incentive compensation plan to provide employees with rewards for the achievement of corporate goals and individual, professional accomplishments. Specific awards are at the discretion of the Compensation and Human Resources Committee of the Board of Directors.
401(k) Savings Plan. During the year ended December 31, 2007, our employees participated in four 401(k) savings plans, all of which meet the requirements of Section 401(k) of the Internal Revenue Code and are defined contribution plans subject to the provisions of ERISA. The following summarizes the plans:
| • | Dynegy Inc. 401(k) Savings Plan. This plan and the related trust fund are established and maintained for the exclusive benefit of participating employees in the United States. All employees of designated Dynegy subsidiaries are eligible to participate in the plan. Employee pre-tax contributions to the plan are matched 100 percent, up to a maximum of 5 percent of base pay, subject to IRS limitations. Vesting in our contributions is based on years of service at 25 percent per full year of service. We may also make annual discretionary contributions to employee accounts, subject to our performance. Matching and discretionary contributions, if any, are allocated in the form of units in the Dynegy common stock fund. During the years ended December 31, 2007, 2006 and 2005, we issued approximately 0.3 million, 0.3 million and 0.9 million shares, respectively, of our common stock in the form of matching contributions to fund the plan. No discretionary contributions were made for any of the years in the three-year period ended December 31, 2007. |
F-78
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| • | Dynegy Midwest Generation, Inc. 401(K) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan) and Dynegy Midwest Generation, Inc. 401(K) Savings Plan for Employees Covered Under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered Under A Collective Bargaining Agreement). We match 50 percent of employee contributions to the plans, up to a maximum of 6 percent of compensation, subject to IRS limitations. Employees are immediately 100 percent vested in our contributions. Matching contributions to the plans are allocated in the form of units in the Dynegy common stock fund. During the years ended December 31, 2007, 2006 and 2005, we issued 0.1 million, 0.2 million and 0.2 million shares, respectively, of our common stock in the form of matching contributions to the plans. |
| • | Dynegy Northeast Generation, Inc. Savings Incentive Plan. Under this plan, which is for union and non-union employees, we match 24 percent of employee contributions up to 6 percent of base salary for union employees and 50 percent of employee contributions up to 8 percent of base salary for non-union employees, in each case subject to IRS limitations. Employees are immediately 100 percent vested in our contributions. Matching contributions to this plan are made in cash and invested according to the employee’s investment discretion. |
During the years ended December 31, 2007, 2006 and 2005, we recognized aggregate costs related to these employee compensation plans of $4 million, $3 million and $5 million, respectively.
Pension and Other Post-Retirement Benefits
We have various defined benefit pension plans and post-retirement benefit plans. All domestic employees participate in the pension plans, but only some of our domestic employees participate in the other post-retirement medical and life insurance benefit plans. Our pension plans are in the form of a cash balance plan and more traditional career average or final average pay formula plans.
Obligations and Funded Status. The following tables contain information about the obligations and funded status of these plans on a combined basis:
| Pension Benefits |
Other Benefits |
|||||||||||||||
| 2007 |
2006 |
2007 |
2006 |
|||||||||||||
| (in millions) | ||||||||||||||||
| Projected benefit obligation, beginning of the year |
$ | 182 | $ | 181 | $ | 61 | $ | 55 | ||||||||
| Service cost |
10 | 9 | 3 | 3 | ||||||||||||
| Interest cost |
10 | 10 | 4 | 3 | ||||||||||||
| Actuarial (gain) loss |
(15 | ) | (6 | ) | (9 | ) | 1 | |||||||||
| Benefits paid |
(5 | ) | (12 | ) | (1 | ) | (1 | ) | ||||||||
| Projected benefit obligation, end of the year |
$ | 182 | $ | 182 | $ | 58 | $ | 61 | ||||||||
| Fair value of plan assets, beginning of the year |
$ | 135 | $ | 118 | $ | — | $ | — | ||||||||
| Actual return on plan assets |
10 | 15 | — | — | ||||||||||||
| Employer contributions |
14 | 14 | 1 | 1 | ||||||||||||
| Benefits paid |
(5 | ) | (12 | ) | (1 | ) | (1 | ) | ||||||||
| Fair value of plan assets, end of the year |
$ | 154 | $ | 135 | $ | — | $ | — | ||||||||
| Funded status |
$ | (28 | ) | $ | (47 | ) | $ | (58 | ) | $ | (61 | ) | ||||
F-79
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The accumulated benefit obligation for all defined benefit pension plans was $125 million and $157 million at December 31, 2007 and 2006, respectively. On December 31, 2006, our annual measurement date, the accumulated benefit obligation related to certain of our pension plans exceeded the fair value of the pension plan assets. The following summarizes information for pension plans with an accumulated benefit obligation in excess of plan assets:
| December 31, | ||||||
| 2007 |
2006 | |||||
| (in millions) | ||||||
| Projected benefit obligation |
$ | 143 | $ | 182 | ||
| Accumulated benefit obligation |
125 | 157 | ||||
| Fair value of plan assets |
120 | 135 | ||||
On September 29, 2006, the FASB issued SFAS No. 158. SFAS No. 158 requires employers to recognize the overfunded or underfunded status of a defined benefit or other postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position, and to recognize changes in that funded status in the year in which the changes occur through comprehensive income.
Under SFAS No. 158, adjustments to the minimum pension liability were eliminated. In the year of adoption, we were required to adjust the minimum pension liability for a final time in accordance with SFAS No. 87. Our adjustment for the year ended December 31, 2006 was $15 million (pre-tax), with an offset to accumulated other comprehensive income (loss). The following table summarizes the change to accumulated other comprehensive income (loss) associated with the minimum pension liability:
| 2007 |
2006 |
2005 |
||||||||
| (in millions) | ||||||||||
| Change in minimum liability included in other comprehensive income (loss) (net of tax benefit (expense) of zero, $(5) million and $3 million, respectively) |
$ | — | $ | 10 | $ | (5 | ) | |||
Subsequent to the final minimum pension liability adjustment, we were required to recognize as a component of Accumulated other comprehensive income (loss) the gains or losses and prior service costs that existed at December 31, 2006, but that had not been recognized as components of net period benefit cost pursuant to SFAS No. 87 and SFAS No. 106. As a result, the pre-tax amounts recognized in accumulated other comprehensive income (loss) consist of:
| Year Ended December 31, | ||||||||||||
| 2007 |
2006 | |||||||||||
| Pension Benefits |
Other Benefits |
Pension Benefits |
Other Benefits | |||||||||
| (in millions) | ||||||||||||
| Prior service cost |
$ | 6 | $ | — | $ | 7 | $ | — | ||||
| Actuarial loss |
22 | 13 | 37 | 23 | ||||||||
| Net amount recognized |
$ | 28 | $ | 13 | $ | 44 | $ | 23 | ||||
F-80
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following table summarizes the incremental effect of the application of SFAS No. 158 on Accumulated other comprehensive income (loss), as well as other line items impacted on the balance sheet:
| Before Application of SFAS No. 158 |
Adjustment |
After Application of SFAS No. 158 |
||||||||||
| (in millions) | ||||||||||||
| Intangible asset |
$ | 7 | $ | (7 | ) | $ | — | |||||
| Accrued benefit liability |
(59 | ) | (49 | ) | (108 | ) | ||||||
| Deferred tax asset |
4 | 21 | 25 | |||||||||
| Accumulated other comprehensive income, pre-tax |
12 | 56 | 68 | |||||||||
| Accumulated other comprehensive income, tax impact |
(4 | ) | (21 | ) | (25 | ) | ||||||
Amounts recognized in the consolidated balance sheets consist of:
| Year Ended December 31, |
||||||||||||||||
| 2007 |
2006 |
|||||||||||||||
| Pension Benefits |
Other Benefits |
Pension Benefits |
Other Benefits |
|||||||||||||
| (in millions) | ||||||||||||||||
| Current liabilities |
$ | — | $ | (1 | ) | $ | — | $ | (1 | ) | ||||||
| Noncurrent liabilities |
(28 | ) | (57 | ) | (47 | ) | (60 | ) | ||||||||
| Net amount recognized |
$ | (28 | ) | $ | (58 | ) | $ | (47 | ) | $ | (61 | ) | ||||
The estimated net actuarial loss and prior service cost that will be amortized from Accumulated other comprehensive income (loss) into net periodic benefit cost during the year ended December 31, 2008 for the defined benefit pension plans are less than $1 million and $1 million, respectively. The estimated net actuarial loss and prior service cost that will be amortized from Accumulated other comprehensive income into net periodic benefit cost during the year ended December 31, 2008 for other postretirement benefit plans are $1 million and zero, respectively. The amortization of prior service cost is determined using a straight line amortization of the cost over the average remaining service period of employees expected to receive benefits under the Plan.
Components of Net Periodic Benefit Cost. The components of net periodic benefit cost were:
| Pension Benefits |
Other Benefits | ||||||||||||||||||||
| 2007 |
2006 |
2005 |
2007 |
2006 |
2005 | ||||||||||||||||
| (in millions) | |||||||||||||||||||||
| Service cost benefits earned during period |
$ | 10 | $ | 9 | $ | 11 | $ | 3 | $ | 3 | $ | 2 | |||||||||
| Interest cost on projected benefit obligation |
10 | 10 | 9 | 4 | 3 | 3 | |||||||||||||||
| Expected return on plan assets |
(11 | ) | (10 | ) | (8 | ) | — | — | — | ||||||||||||
| Amortization of prior service costs |
1 | 1 | 1 | — | — | — | |||||||||||||||
| Recognized net actuarial loss |
1 | 3 | 2 | 1 | 1 | 1 | |||||||||||||||
| Net periodic benefit cost |
$ | 11 | $ | 13 | $ | 15 | $ | 8 | $ | 7 | $ | 6 | |||||||||
| Additional cost due to curtailment |
— | 3 | 3 | — | — | — | |||||||||||||||
| Total net periodic benefit cost |
$ | 11 | $ | 16 | $ | 18 | $ | 8 | $ | 7 | $ | 6 | |||||||||
F-81
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Assumptions. The following weighted average assumptions were used to determine benefit obligations:
| Pension Benefits |
Other Benefits |
|||||||||||
| December 31, |
December 31, |
|||||||||||
| 2007 |
2006 |
2007 |
2006 |
|||||||||
| Discount rate (1) |
6.46 | % | 5.87 | % | 6.48 | % | 5.90 | % | ||||
| Rate of compensation increase |
4.50 | % | 4.50 | % | 4.50 | % | 4.50 | % | ||||
| (1) | We utilized a yield curve approach to determine the discount rate as of December 31, 2007 and 2006. Projected benefit payments for the plans were matched against the discount rates in the yield curve. |
The following weighted average assumptions were used to determine net periodic benefit cost:
| Pension Benefits |
Other Benefits |
|||||||||||||||||
| Year Ended December 31, |
Year Ended December 31, |
|||||||||||||||||
| 2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
|||||||||||||
| Discount rate |
5.87 | % | 5.52 | % | 5.75 | % | 5.90 | % | 5.53 | % | 5.75 | % | ||||||
| Expected return on plan assets |
8.25 | % | 8.25 | % | 8.25 | % | N/A | N/A | N/A | |||||||||
| Rate of compensation increase |
4.50 | % | 4.50 | % | 4.50 | % | 4.50 | % | 4.50 | % | 4.50 | % | ||||||
Our expected long-term rate of return on plan assets for the year ended December 31, 2008 will be 8.25 percent. This figure begins with a blend of asset class-level returns developed under a theoretical global capital asset pricing model methodology conducted by an outside consultant. In development of this figure, the historical relationships between equities and fixed income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long-term. Current market factors such as inflation and interest rates are also incorporated in the assumptions. The figure also incorporates an upward adjustment reflecting the plan’s use of active management and favorable past experience.
The following summarizes our assumed health care cost trend rates:
| December 31, |
||||||
| 2007 |
2006 |
|||||
| Health care cost trend rate assumed for next year |
8.99 | % | 9.69 | % | ||
| Ultimate trend rate |
5.00 | % | 5.00 | % | ||
| Year that the rate reaches the ultimate trend rate |
2016 | 2016 | ||||
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The impact of a one percent increase/decrease in assumed health care cost trend rates is as follows:
| Increase |
Decrease |
||||||
| (in millions) | |||||||
| Aggregate impact on service cost and interest cost |
$ | 1 | $ | (1 | ) | ||
| Impact on accumulated post-retirement benefit obligation |
$ | 10 | $ | (8 | ) | ||
Plan Assets. We employ a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. The intent of this strategy is to minimize plan expenses by outperforming plan liabilities over the long run. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks as well as growth, value, and small and large capitalizations.
F-82
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying investment. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, periodic asset/liability studies, and annual liability measurements.
Our pension plans’ weighted-average asset allocations by asset category were as follows:
| December 31, |
||||||
| 2007 |
2006 |
|||||
| Equity securities |
64 | % | 71 | % | ||
| Debt securities |
36 | % | 29 | % | ||
| Total |
100 | % | 100 | % | ||
Equity securities did not include any of Dynegy’s common stock at December 31, 2007 or 2006.
Contributions. During the year ended December 31, 2007, we contributed approximately $14 million to our pension plans and $1 million to our other post-retirement benefit plans. In 2008, we expect to contribute approximately $29 million to our pension plans and $1 million to our other postretirement benefit plans.
Our expected benefit payments for future services for our pension and other postretirement benefits are as follows:
| Pension Benefits |
Other Benefits | |||||
| (in millions) | ||||||
| 2008 |
$ | 9 | $ | 1 | ||
| 2009 |
8 | 1 | ||||
| 2010 |
8 | 2 | ||||
| 2011 |
7 | 2 | ||||
| 2012 |
9 | 3 | ||||
| 2013 – 2017 |
64 | 20 | ||||
Note 22—Segment Information
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 continue to separately report the results of our CRM business. Results associated with our former NGL segment are included in discontinued operations in Other due to the sale of this business. Our consolidated financial results also reflect corporate-level expenses such as general and administrative and 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.
During 2007, two customers in our GEN-MW segment and one customer in our GEN-NE segment accounted for approximately 23 percent, 11 percent and 17 percent of our consolidated revenues, respectively. During 2006, two customers in our GEN-MW segment and one customer in our GEN-NE segment accounted for approximately 23 percent, 19 percent and 18 percent of our consolidated revenues, respectively.
F-83
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Pursuant to EITF Issue 02-3, all gains and losses on third party energy trading contracts in the CRM business, whether realized or unrealized, are presented net in the consolidated statements of operations. For the purpose of the segment data presented below, intersegment transactions between CRM and our other segments are presented net in CRM intersegment revenues but are presented gross in the intersegment revenues of our other segments, as the activities of our other segments are not subject to the net presentation requirements contained in EITF Issue 02-3. If transactions between CRM and our other segments result in a net intersegment purchase by CRM, the net intersegment purchases and sales are presented as negative revenues in CRM intersegment revenues. In addition, intersegment hedging activities are presented net pursuant to SFAS No. 133. In the second quarter 2007, we discontinued the use of hedge accounting for certain derivative transactions affecting the GEN-MW, GEN-WE and GEN-NE segments. The operating results presented herein reflect the changes in market values of derivative instruments entered into by each of these segments. Please read Note 6—Risk Management Activities and Financial Instruments for further discussion.
Reportable segment information for Dynegy, including intercompany transactions accounted for at prevailing market rates, for the years ended December 31, 2007, 2006 and 2005 is presented below:
Dynegy’s Segment Data for the Year Ended December 31, 2007
(in millions)
| Power Generation |
CRM |
Other and Eliminations |
Total |
|||||||||||||||||||||
| GEN-MW |
GEN-WE |
GEN-NE |
||||||||||||||||||||||
| Unaffiliated revenues: |
||||||||||||||||||||||||
| Domestic |
$ | 1,325 | $ | 689 | $ | 920 | $ | 12 | $ | — | $ | 2,946 | ||||||||||||
| Other |
— | — | 156 | 1 | — | 157 | ||||||||||||||||||
| Total revenues |
$ | 1,325 | $ | 689 | $ | 1,076 | $ | 13 | $ | — | $ | 3,103 | ||||||||||||
| Depreciation and amortization |
$ | (194 | ) | $ | (73 | ) | $ | (45 | ) | $ | — | $ | (13 | ) | $ | (325 | ) | |||||||
| 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 | ||||||||||||||||||||||
| Identifiable assets: |
||||||||||||||||||||||||
| Domestic |
$ | 6,425 | $ | 3,743 | $ | 1,942 | $ | 303 | $ | 772 | $ | 13,185 | ||||||||||||
| Other |
— | 5 | 12 | 19 | — | 36 | ||||||||||||||||||
| Total |
$ | 6,425 | $ | 3,748 | $ | 1,954 | $ | 322 | $ | 772 | $ | 13,221 | ||||||||||||
| Unconsolidated investments |
$ | — | $ | 18 | $ | — | $ | — | $ | 61 | $ | 79 | ||||||||||||
| Capital expenditures |
$ | (300 | ) | $ | (17 | ) | $ | (47 | ) | $ | — | $ | (15 | ) | $ | (379 | ) | |||||||
F-84
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Dynegy’s Segment Data for the Year Ended December 31, 2006
(in millions)
| Power Generation |
CRM |
Other and Eliminations |
Total |
||||||||||||||||||||
| GEN-MW |
GEN-WE |
GEN-NE |
|||||||||||||||||||||
| Unaffiliated revenues: |
|||||||||||||||||||||||
| Domestic |
$ | 969 | $ | 87 | $ | 501 | $ | 66 | $ | — | $ | 1,623 | |||||||||||
| Other |
— | — | 129 | 18 | — | 147 | |||||||||||||||||
| 969 | 87 | 630 | 84 | — | 1,770 | ||||||||||||||||||
| Intersegment revenues |
— | — | (21 | ) | 21 | — | — | ||||||||||||||||
| Total revenues |
$ | 969 | $ | 87 | $ | 609 | $ | 105 | $ | — | $ | 1,770 | |||||||||||
| Depreciation and amortization |
$ | (168 | ) | $ | (8 | ) | $ | (24 | ) | $ | — | $ | (17 | ) | $ | (217 | ) | ||||||
| Impairment and other charges |
(110 | ) | (9 | ) | — | — | — | (119 | ) | ||||||||||||||
| Operating income (loss) |
$ | 208 | $ | (2 | ) | $ | 55 | $ | 7 | $ | (163 | ) | $ | 105 | |||||||||
| Earnings (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 | ) | ||||||||||||||||||||
| Identifiable assets: |
|||||||||||||||||||||||
| Domestic |
$ | 4,959 | $ | 517 | $ | 1,373 | $ | 287 | $ | 203 | $ | 7,339 | |||||||||||
| Other |
— | 5 | 13 | 180 | — | 198 | |||||||||||||||||
| Total |
$ | 4,959 | $ | 522 | $ | 1,386 | $ | 467 | $ | 203 | $ | 7,537 | |||||||||||
| Capital expenditures |
$ | (101 | ) | $ | (24 | ) | $ | (22 | ) | $ | — | $ | (8 | ) | $ | (155 | ) | ||||||
F-85
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Dynegy’s Segment Data for the Year Ended December 31, 2005
(in millions)
| Power Generation |
CRM |
Other and Eliminations |
Total |
|||||||||||||||||||||
| GEN-MW |
GEN-WE |
GEN-NE |
||||||||||||||||||||||
| Unaffiliated revenues: |
||||||||||||||||||||||||
| Domestic |
$ | 947 | $ | 144 | $ | 772 | $ | 72 | $ | — | $ | 1,935 | ||||||||||||
| Other |
— | — | 127 | (45 | ) | — | 82 | |||||||||||||||||
| 947 | 144 | 899 | 27 | — | 2,017 | |||||||||||||||||||
| Intersegment revenues |
— | (35 | ) | 3 | 32 | — | — | |||||||||||||||||
| Total revenues |
$ | 947 | $ | 109 | $ | 902 | $ | 59 | $ | — | $ | 2,017 | ||||||||||||
| Depreciation and amortization |
$ | (157 | ) | $ | (11 | ) | $ | (21 | ) | $ | (1 | ) | $ | (18 | ) | $ | (208 | ) | ||||||
| Impairment and other charges |
(36 | ) | — | — | — | (10 | ) | (46 | ) | |||||||||||||||
| 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 | ||||||||||||||||||||||
| Identifiable assets: |
||||||||||||||||||||||||
| Domestic |
$ | 4,926 | $ | 996 | $ | 1,520 | $ | 1,014 | $ | 1,524 | $ | 9,980 | ||||||||||||
| Other |
— | 5 | 38 | 103 | — | 146 | ||||||||||||||||||
| Total |
$ | 4,926 | $ | 1,001 | $ | 1,558 | $ | 1,117 | $ | 1,524 | $ | 10,126 | ||||||||||||
| Unconsolidated investments |
$ | 60 | $ | 210 | $ | — | $ | — | $ | — | $ | 270 | ||||||||||||
| Capital expenditures and investments in unconsolidated affiliates |
$ | (113 | ) | $ | (9 | ) | $ | (21 | ) | $ | — | $ | (52 | ) | $ | (195 | ) | |||||||
F-86
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Reportable segment information for DHI, including intercompany transactions accounted for at prevailing market rates, for the years ended December 31, 2007, 2006 and 2005 is presented below:
DHI’s Segment Data for the Year Ended December 31, 2007
(in millions)
| Power Generation |
Other and Eliminations |
|||||||||||||||||||||||
| GEN-MW |
GEN-WE |
GEN-NE |
CRM |
Total |
||||||||||||||||||||
| Unaffiliated revenues: |
||||||||||||||||||||||||
| Domestic |
$ | 1,325 | $ | 689 | $ | 920 | $ | 12 | $ | — | $ | 2,946 | ||||||||||||
| Other |
— | — | 156 | 1 | — | 157 | ||||||||||||||||||
| Total revenues |
$ | 1,325 | $ | 689 | $ | 1,076 | $ | 13 | $ | — | $ | 3,103 | ||||||||||||
| Depreciation and amortization |
$ | (194 | ) | $ | (73 | ) | $ | (45 | ) | $ | — | $ | (13 | ) | $ | (325 | ) | |||||||
| 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 | ||||||||||||||||||||||
| Identifiable assets: |
||||||||||||||||||||||||
| Domestic |
$ | 6,425 | $ | 3,748 | $ | 1,942 | $ | 315 | $ | 658 | $ | 13,088 | ||||||||||||
| Other |
— | — | 12 | 7 | — | 19 | ||||||||||||||||||
| Total |
$ | 6,425 | $ | 3,748 | $ | 1,954 | $ | 322 | $ | 658 | $ | 13,107 | ||||||||||||
| Unconsolidated investments |
$ | — | $ | 18 | $ | — | $ | — | $ | — | $ | 18 | ||||||||||||
| Capital expenditures |
$ | (300 | ) | $ | (17 | ) | $ | (47 | ) | $ | — | $ | (15 | ) | $ | (379 | ) | |||||||
F-87
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DHI’s Segment Data for the Year Ended December 31, 2006
(in millions)
| Power Generation |
Other and Eliminations |
||||||||||||||||||||||
| GEN-MW |
GEN-WE |
GEN-NE |
CRM |
Total |
|||||||||||||||||||
| Unaffiliated revenues: |
|||||||||||||||||||||||
| Domestic |
$ | 969 | $ | 87 | $ | 501 | $ | 66 | $ | — | $ | 1,623 | |||||||||||
| Other |
— | — | 129 | 18 | — | 147 | |||||||||||||||||
| 969 | 87 | 630 | 84 | — | 1,770 | ||||||||||||||||||
| Intersegment revenues |
— | — | (21 | ) | 21 | — | — | ||||||||||||||||
| Total revenues |
$ | 969 | $ | 87 | $ | 609 | $ | 105 | $ | — | $ | 1,770 | |||||||||||
| Depreciation and amortization |
$ | (168 | ) | $ | (8 | ) | $ | (24 | ) | $ | — | $ | (17 | ) | $ | (217 | ) | ||||||
| Impairment and other charges |
(110 | ) | (9 | ) | — | — | — | (119 | ) | ||||||||||||||
| 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 | ) | ||||||||||||||||||||
| Identifiable assets: |
|||||||||||||||||||||||
| Domestic |
$ | 4,961 | $ | 517 | $ | 1,373 | $ | 439 | $ | 776 | $ | 8,066 | |||||||||||
| Other |
— | — | 13 | 57 | — | 70 | |||||||||||||||||
| Total |
$ | 4,961 | $ | 517 | $ | 1,386 | $ | 496 | $ | 776 | $ | 8,136 | |||||||||||
| Capital expenditures |
$ | (101 | ) | $ | (24 | ) | $ | (22 | ) | $ | — | $ | (8 | ) | $ | (155 | ) | ||||||
F-88
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DHI’s Segment Data for the Year Ended December 31, 2005
(in millions)
| Power Generation |
Other and Eliminations |
|||||||||||||||||||||||
| GEN-MW |
GEN-WE |
GEN-NE |
CRM |
Total |
||||||||||||||||||||
| Unaffiliated revenues: |
||||||||||||||||||||||||
| Domestic |
$ | 947 | $ | 144 | $ | 772 | $ | 72 | $ | — | $ | 1,935 | ||||||||||||
| Other |
— | — | 127 | (45 | ) | — | 82 | |||||||||||||||||
| 947 | 144 | 899 | 27 | — | 2,017 | |||||||||||||||||||
| Intersegment revenues |
— | (35 | ) | 3 | 32 | — | — | |||||||||||||||||
| Total revenues |
$ | 947 | $ | 109 | $ | 902 | $ | 59 | $ | — | $ | 2,017 | ||||||||||||
| Depreciation and amortization |
$ | (157 | ) | $ | (11 | ) | $ | (21 | ) | $ | (1 | ) | $ | (18 | ) | $ | (208 | ) | ||||||
| Impairment and other charges |
(30 | ) | — | — | — | (10 | ) | (40 | ) | |||||||||||||||
| 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 | ||||||||||||||||||||||
| Identifiable assets: |
||||||||||||||||||||||||
| Domestic |
$ | 3,830 | $ | 1,386 | $ | 1,358 | $ | 59 | $ | 3,164 | $ | 9,797 | ||||||||||||
| Other |
— | — | 90 | 693 | — | 783 | ||||||||||||||||||
| Total |
$ | 3,830 | $ | 1,386 | $ | 1,448 | $ | 752 | $ | 3,164 | $ | 10,580 | ||||||||||||
| Unconsolidated investments |
$ | 60 | $ | 207 | $ | — | $ | — | $ | — | $ | 267 | ||||||||||||
| Capital expenditures and investments in unconsolidated affiliates |
$ | (113 | ) | $ | (9 | ) | $ | (21 | ) | $ | — | $ | (52 | ) | $ | (195 | ) | |||||||
F-89
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Note 23—Quarterly Financial Information (Unaudited)
The following is a summary of Dynegy’s unaudited quarterly financial information for the years ended December 31, 2007 and 2006:
| Quarter Ended |
|||||||||||||||
| March 2007 |
June 2007 |
September 2007 |
December 2007 |
||||||||||||
| (in millions, except per share data) | |||||||||||||||
| Revenues |
$ | 505 | $ | 828 | $ | 1,046 | $ | 724 | |||||||
| Operating income |
81 | 182 | 247 | 95 | |||||||||||
| Income (loss) before cumulative effect of change in accounting principles |
14 | 76 | (1) | 220 | (2) | (46 | ) | ||||||||
| Net income (loss) |
14 | 76 | (1) | 220 | (2) | (46 | )(3) | ||||||||
| Income (loss) per share before cumulative effect of change in accounting principles |
$ | 0.03 | $ | 0.09 | (1) | $ | 0.26 | (2) | $ | (0.06 | )(3) | ||||
| Net income (loss) per share |
$ | 0.03 | $ | 0.09 | (1) | $ | 0.26 | (2) | $ | (0.06 | )(3) | ||||
| (1) | Includes a pre-tax gain of $30 million related to a change in the fair value of interest rate swaps, net of minority interest, and a pre-tax gain of $31 million related to the settlement of the Kendall tolling arrangement. |
| (2) | Includes a pre-tax gain on the sale of the CoGen Lyondell power generation facility of $210 million. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—GEN-WE Discontinued Operations—CoGen Lyondell for further information. |
| (3) | Includes tax expense of approximately $50 million resulting from an increase in Dynegy’s estimated state tax rate. Also includes a pre-tax gain of $39 million related to the sale of a portion of our interest in the Plum Point Project. |
| Quarter Ended |
||||||||||||||||
| March 2006 |
June 2006 |
September 2006 |
December 2006 |
|||||||||||||
| (in millions, except per share data) | ||||||||||||||||
| Revenues |
$ | 540 | $ | 379 | $ | 508 | $ | 343 | ||||||||
| Operating income (loss) |
92 | 20 | (20 | ) | 13 | |||||||||||
| Loss before cumulative effect of change in accounting principles |
— | (207 | )(1) | (69 | )(2) | (58 | ) | |||||||||
| Net income (loss) |
1 | (207 | )(1) | (69 | )(2) | (58 | ) | |||||||||
| Net loss per share before cumulative effect of change in accounting principles |
$ | (0.01 | ) | $ | (0.48 | )(1) | $ | (0.14 | )(2) | $ | (0.12 | ) | ||||
| Net loss per share |
$ | (0.01 | ) | $ | (0.48 | )(1) | $ | (0.14 | )(2) | $ | (0.12 | ) | ||||
| (1) | Includes a pre-tax charge for debt conversion costs of $247 million and a pre-tax charge of $33 million related to the acceleration of deferred financing costs. Please read Note 15—Debt for further discussion. |
| (2) | Includes a pre-tax impairment charge of $96 million related to our Bluegrass power generation facility. Please read Note 5—Restructuring and Impairment Charges—Asset Impairments for further discussion. Also includes a pre-tax charge of $36 million related to the exchange of our Sithe subordinated debentures. |
The following is a summary of DHI’s unaudited quarterly financial information for the years ended December 31, 2007 and 2006:
| Quarter Ended |
|||||||||||||||
| March 2007 |
June 2007 |
September 2007 |
December 2007 |
||||||||||||
| (in millions, except per share data) | |||||||||||||||
| Revenues |
$ | 505 | $ | 828 | $ | 1,046 | $ | 724 | |||||||
| Operating income |
98 | 184 | 247 | 95 | |||||||||||
| Income (loss) before cumulative effect of change in accounting principles |
22 | 90 | (1) | 222 | (2) | (10 | )(3) | ||||||||
| Net income (loss) |
22 | 90 | (1) | 222 | (2) | (10 | )(3) | ||||||||
F-90
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| (1) | Includes a pre-tax gain of $30 million related to a change in the fair value of interest rate swaps, net of minority interest, and a pre-tax gain of $31 million related to the settlement of the Kendall tolling arrangement. |
| (2) | Includes a pre-tax gain on the sale of the CoGen Lyondell power generation facility of $210 million. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—GEN-WE Discontinued Operations—CoGen Lyondell for further information. |
| (3) | Includes tax expense of approximately $25 million resulting from an increase in DHI’s estimated state tax rate. Also includes a pre-tax gain of $39 million related to the sale of a portion of our interest in the Plum Point Project. |
| Quarter Ended |
|||||||||||||||
| March 2006 |
June 2006 |
September 2006 |
December 2006 |
||||||||||||
| (in millions, except per share data) | |||||||||||||||
| Revenues |
$ | 540 | $ | 379 | $ | 508 | $ | 343 | |||||||
| Operating income (loss) |
92 | 21 | (19 | ) | 14 | ||||||||||
| Income (loss) before cumulative effect of change in accounting principles |
3 | (181 | )(1) | (67 | )(2) | (63 | ) | ||||||||
| Net income (loss) |
3 | (181 | )(1) | (67 | )(2) | (63 | ) | ||||||||
| (1) | Includes pre-tax debt conversion costs of $202 million and a pre-tax charge of $33 million related to the acceleration of deferred financing costs. Please read Note 15—Debt for further discussion. |
| (2) | Includes a pre-tax impairment charge of $96 million related to our Bluegrass power generation facility. Please read Note 5—Restructuring and Impairment Charges—Asset Impairments for further discussion. Also includes a pre-tax charge of $36 million related to the exchange of our Sithe subordinated debentures. |
F-91
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DEFINITIONS
As used in this Form 10-K, the abbreviations listed below have the following meanings:
| APB |
Accounting Principles Board | |
| APIC |
Additional paid-in-capital | |
| ARB |
Accounting Research Bulletin | |
| ARO |
Asset retirement obligation | |
| BTA |
Best technology available | |
| CAA |
Clean Air Act | |
| CAIR |
Clean Air Interstate Rule | |
| CAMR |
Clean Air Mercury Rule | |
| CAISO |
The California Independent System Operator | |
| CERCLA |
The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended | |
| CO2 |
Carbon dioxide | |
| COSO |
Committee of Sponsoring Organizations of the Treadway Commission | |
| CRA |
Canada Revenue Authority | |
| CRM |
Our customer risk management business segment | |
| DHI |
Dynegy Holdings Inc., Dynegy’s primary financing subsidiary | |
| DMG |
Dynegy Midwest Generation | |
| DMSLP |
Dynegy Midstream Services L.P. | |
| DMT |
Dynegy Marketing and Trade | |
| DNE |
Dynegy Northeast Generation | |
| DPM |
Dynegy Power Marketing Inc | |
| EITF |
Emerging Issues Task Force | |
| ERISA |
The Employee Retirement Income Security Act of 1974, as amended | |
| FASB |
Financial Accounting Standards Board | |
| FCM |
Forward Capacity Market | |
| FERC |
Federal Energy Regulatory Commission | |
| FIN |
FASB Interpretation | |
| FSP |
FASB Staff Position | |
| FTC |
U.S. Federal Trade Commission | |
| FTRs |
Financial Transmission Rights | |
| GAAP |
Generally Accepted Accounting Principles of the United States of America | |
| GEN |
Our power generation business | |
| GEN-MW |
Our power generation business—Midwest segment | |
| GEN-NE |
Our power generation business—Northeast segment | |
| GEN-SO |
Our power generation business—South segment, which was renamed GEN-WE | |
| GEN-WE |
Our power generation business—West segment | |
| ICC |
Illinois Commerce Commission | |
| IRS |
Internal Revenue Service | |
| ISO |
Independent System Operator | |
| ISO-NE |
Independent System Operator—New England | |
| LMP |
Locational Marginal Pricing | |
| LNG |
Liquefied natural gas | |
| MISO |
Midwest Independent Transmission System Operator | |
| MMBtu |
Millions of British thermal units | |
| MW |
Megawatts |
F-92
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| MWh |
Megawatt hour | |
| NERC |
North American Electric Reliability Council | |
| NGL |
Our natural gas liquids business segment | |
| NOL |
Net operating loss | |
| NOx |
Nitrogen oxide | |
| NPDES |
National Pollutant Discharge Elimination System | |
| NYISO |
New York Independent System Operator | |
| NYSDEC |
New York State Department of Environmental Conservation | |
| PCAOB |
Public Company Accounting Oversight Board (United States) | |
| PJM |
PJM Interconnection, LLC | |
| PPA |
Power purchase agreement | |
| PPEA |
Plum Point Energy Associates | |
| PRB |
Powder River Basin coal | |
| PURPA |
The Public Utility Regulatory Policies Act of 1978 | |
| QF |
Qualifying Facility | |
| RCRA |
The Resource Conservation and Recovery Act of 1976, as amended | |
| RGGI |
Regional Greenhouse Gas Initiative | |
| RMR |
Reliability Must Run | |
| RTO |
Regional Transmission Organization | |
| SAB |
SEC Staff Accounting Bulletin | |
| SEC |
U.S. Securities and Exchange Commission | |
| SERC |
Southeastern Electric Reliability Council | |
| SFAS |
Statement of Financial Accounting Standards | |
| SO2 |
Sulfur dioxide | |
| SPE |
Special Purpose Entity | |
| SPDES |
State Pollutant Discharge Elimination System | |
| SPN |
Second Priority Senior Secured Notes | |
| U.S. EPA |
United States Environmental Protection Agency | |
| VaR |
Value at Risk | |
| VIE |
Variable Interest Entity | |
| VLGC |
Very large gas carrier | |
| WAPA |
Western Area Power Administration | |
| WECC |
Western Electricity Coordinating Council |
F-93
DYNEGY INC.
CONDENSED BALANCE SHEETS OF THE REGISTRANT
(in millions)
| December 31, 2007 |
December 31, 2006 |
|||||||
| ASSETS |
||||||||
| Current Assets |
||||||||
| Cash and cash equivalents |
$ | 35 | $ | 121 | ||||
| Intercompany accounts receivable |
1,756 | 1,431 | ||||||
| Deferred income taxes |
45 | 93 | ||||||
| Total Current Assets |
1,836 | 1,645 | ||||||
| Other Assets |
||||||||
| Investments in affiliates |
6,101 | 3,321 | ||||||
| Unconsolidated investments |
61 | — | ||||||
| Deferred income taxes |
6 | 12 | ||||||
| Other long-term assets |
— | 9 | ||||||
| Total Assets |
$ | 8,004 | $ | 4,987 | ||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY |
||||||||
| Current Liabilities |
||||||||
| Accounts payable |
$ | 5 | $ | 8 | ||||
| Total Current Liabilities |
5 | 8 | ||||||
| Intercompany long-term debt |
2,243 | 2,243 | ||||||
| Deferred income taxes |
1,250 | 469 | ||||||
| Total Liabilities |
3,498 | 2,720 | ||||||
| Commitments and Contingencies (Note 3) |
||||||||
| Stockholders’ Equity |
||||||||
| Class A Common Stock, $0.01 par value, 2,100,000,000 shares authorized at December 31, 2007; 502,819,794 shares issued and outstanding at December 31, 2007; and no par value, 900,000,000 shares authorized at December 31, 2006; 403,137,339 shares issued and outstanding at December 31, 2006 |
5 | 3,367 | ||||||
| Class B Common Stock, $0.01 par value, 850,000,000 shares authorized at December 31, 2007; 340,000,000 shares issued and outstanding at December 31, 2007; and no par value, 360,000,000 shares authorized at December 31, 2006; 96,891,014 shares issued and outstanding at December 31, 2006 |
3 | 1,006 | ||||||
| Additional paid-in capital |
6,463 | 39 | ||||||
| Subscriptions receivable |
(5 | ) | (8 | ) | ||||
| Accumulated other comprehensive income (loss), net of tax |
(25 | ) | 67 | |||||
| Accumulated deficit |
(1,864 | ) | (2,135 | ) | ||||
| Treasury stock, at cost, 2,449,259 shares at December 31, 2007 and 1,787,004 shares at December 31, 2006, respectively |
(71 | ) | (69 | ) | ||||
| Total Stockholders’ Equity |
4,506 | 2,267 | ||||||
| Total Liabilities and Stockholders’ Equity |
$ | 8,004 | $ | 4,987 | ||||
See Notes to Registrant’s Financial Statements and Dynegy Inc.’s Consolidated Financial Statements
F-94
Schedule I
DYNEGY INC.
CONDENSED STATEMENTS OF OPERATIONS OF THE REGISTRANT
(in millions)
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| Operating loss |
$ | — | $ | — | $ | (81 | ) | |||||
| Earnings (losses) from unconsolidated investments |
503 | (452 | ) | 137 | ||||||||
| Interest expense |
— | (6 | ) | (11 | ) | |||||||
| Debt conversion costs |
— | (46 | ) | — | ||||||||
| Other income and expense, net |
3 | 9 | 5 | |||||||||
| Income (loss) before income taxes |
506 | (495 | ) | 50 | ||||||||
| Income tax (expense) benefit |
(242 | ) | 162 | 40 | ||||||||
| Net income (loss) |
264 | (333 | ) | 90 | ||||||||
| Less: preferred stock dividends |
— | 9 | 22 | |||||||||
| Net income (loss) applicable to common stockholders |
$ | 264 | $ | (342 | ) | $ | 68 | |||||
See Notes to Registrant’s Financial Statements and Dynegy Inc.’s Consolidated Financial Statements
F-95
Schedule I
DYNEGY INC.
CONDENSED STATEMENTS OF CASH FLOWS OF THE REGISTRANT
(in millions)
| Year Ended December 31, |
||||||||||||
| 2007 |
2006 |
2005 |
||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||||||
| Operating cash flow, exclusive of intercompany transactions |
$ | 8 | $ | 14 | $ | (6 | ) | |||||
| Intercompany transactions |
46 | 59 | (12 | ) | ||||||||
| Net cash provided by (used in) operating activities |
54 | 73 | (18 | ) | ||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||
| Unconsolidated investments |
(10 | ) | — | — | ||||||||
| Loans to DHI |
— | 120 | (120 | ) | ||||||||
| Business acquisitions, net of cash acquired |
(128 | ) | (8 | ) | — | |||||||
| Net cash provided by (used in) investing activities |
(138 | ) | 112 | (120 | ) | |||||||
| CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||
| Debt conversion costs |
— | (46 | ) | — | ||||||||
| Redemption of Series C Preferred |
— | (400 | ) | — | ||||||||
| Proceeds from issuance of capital stock |
4 | 183 | 2 | |||||||||
| Dividends and other distributions, net |
— | (17 | ) | (22 | ) | |||||||
| Other financing, net |
(6 | ) | — | — | ||||||||
| Net cash used in financing activities |
(2 | ) | (280 | ) | (20 | ) | ||||||
| Net decrease in cash and cash equivalents |
(86 | ) | (95 | ) | (158 | ) | ||||||
| Cash and cash equivalents, beginning of period |
121 | 216 | 374 | |||||||||
| Cash and cash equivalents, end of period |
$ | 35 | $ | 121 | $ | 216 | ||||||
| SUPPLEMENTAL CASH FLOW INFORMATION |
||||||||||||
| Interest paid (net of amount capitalized) |
— | 5 | 11 | |||||||||
| Taxes paid (net of refunds) |
48 | 9 | 45 | |||||||||
| SUPPLEMENTAL NONCASH FLOW INFORMATION |
||||||||||||
| Conversion of Convertible Subordinated Debentures due 2023 |
$ | — | $ | 225 | $ | — | ||||||
| Contribution of Sandy Creek to DHI |
(16 | ) | — | — | ||||||||
See Notes to Registrant’s Financial Statements and Dynegy Inc.’s Consolidated Financial Statements
F-96
Schedule I
DYNEGY INC.
NOTES TO REGISTRANT’S FINANCIAL STATEMENTS
Note 1—Background and Basis of Presentation
These condensed parent company financial statements have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X, as the restricted net assets of Dynegy Inc.’s subsidiaries exceeds 25 percent of the consolidated net assets of Dynegy Inc. These statements should be read in conjunction with the Consolidated Statements and notes thereto of Dynegy Inc.
We are a holding company and conduct substantially all of our business operations through our subsidiaries. We began operations in 1985 and became incorporated in the State of Delaware in 2007 in anticipation of our April 2007 merger with the Contributed Entities.
Note 2—Commitments and Contingencies
For a discussion of our commitments and contingencies, please read Note 19—Commitments and Contingencies of our consolidated financial statements.
Please read Note 15—Debt of our consolidated financial statements and Note 19—Commitments and Contingencies—Guarantees and Indemnifications of our consolidated financial statements for a discussion of our guarantees.
F-97
Schedule II
DYNEGY INC.
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2007, 2006 and 2005
| Balance at Beginning of Period |
Charged to Costs and Expenses |
Charged to Other Accounts |
Deductions |
Balance at End of Period | ||||||||||||||
| (in millions) | ||||||||||||||||||
| 2007 |
||||||||||||||||||
| Allowance for doubtful accounts |
$ | 48 | $ | (3 | ) | $ | (21 | ) | $ | (4 | ) | $ | 20 | |||||
| Allowance for risk-management assets (1) |
— | 11 | — | — | 11 | |||||||||||||
| Deferred tax asset valuation allowance |
69 | (6 | ) | (1 | ) | — | 62 | |||||||||||
| 2006 |
||||||||||||||||||
| Allowance for doubtful accounts |
$ | 103 | $ | (35 | ) | $ | 43 | $ | (63 | ) | $ | 48 | ||||||
| Allowance for risk-management assets (1) |
10 | — | — | (10 | ) | — | ||||||||||||
| Deferred tax asset valuation allowance |
70 | 17 | — | (18 | ) | 69 | ||||||||||||
| 2005 |
||||||||||||||||||
| Allowance for doubtful accounts |
$ | 159 | $ | 1 | $ | — | $ | (57 | ) | $ | 103 | |||||||
| Allowance for risk-management assets (1) |
6 | — | — | 4 | 10 | |||||||||||||
| Deferred tax asset valuation allowance (2) |
136 | — | (5 | ) | (61 | ) | 70 | |||||||||||
| (1) | Changes in price and credit reserves related to risk-management assets are offset in the net mark-to-market income accounts reported in revenues. |
| (2) | Decrease in our deferred tax asset valuation relates to our release of a deferred tax capital gains valuation allowance. |
F-98
Schedule II
DYNEGY HOLDINGS INC.
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2007, 2006 and 2005
| Balance at Beginning of Period |
Charged to Costs and Expenses |
Charged to Other Accounts |
Deductions |
Balance at End of Period | ||||||||||||||
| (in millions) | ||||||||||||||||||
| 2007 |
||||||||||||||||||
| Allowance for doubtful accounts |
$ | 48 | $ | (3 | ) | $ | (21 | ) | $ | (9 | ) | $ | 15 | |||||
| Allowance for risk-management assets (1) |
— | 11 | — | — | 11 | |||||||||||||
| Deferred tax asset valuation allowance |
66 | (6 | ) | (1 | ) | — | 59 | |||||||||||
| 2006 |
||||||||||||||||||
| Allowance for doubtful accounts |
$ | 103 | $ | (35 | ) | $ | 43 | $ | (63 | ) | $ | 48 | ||||||
| Allowance for risk-management assets (1) |
10 | — | — | (10 | ) | — | ||||||||||||
| Deferred tax asset valuation allowance |
52 | 4 | 15 | (5 | ) | 66 | ||||||||||||
| 2005 |
||||||||||||||||||
| Allowance for doubtful accounts |
$ | 169 | $ | 1 | $ | — | $ | (67 | ) | $ | 103 | |||||||
| Allowance for risk-management assets (1) |
6 | — | — | 4 | 10 | |||||||||||||
| Deferred tax asset valuation allowance |
69 | 14 | (63 | ) | 32 | 52 | ||||||||||||
| (1) | Changes in price and credit reserves related to risk-management assets are offset in the net mark-to-market income accounts reported in revenues. |
F-99