We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry and our primary business is the production and sale of electric energy, capacity and ancillary services from our 11,739 MW fleet (20 plants) of owned or leased power generation facilities.
Dynegy began operations in 1985 and became incorporated in the state of Illinois in 1999 in anticipation of our February 2000 acquisition of Illinova Corporation. 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 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.
On September 14, 2006, we entered into a Plan of Merger, Contribution and Sale Agreement (the “Merger Agreement”) with LSP Gen Investors, L.P., LS Power Partners, L.P., LS Power Equity Partners PIE I, L.P., LS Power Associates, L.P., and LS Power Equity Partners, L.P. (collectively, the “LS Entities”), part of the LS Power Group, a privately held power plant investor, developer and manager, to combine a portion of the LS Entities’ operating generation portfolio with our generation assets, and for us to acquire a 50 percent ownership interest in a development company that is currently controlled by the LS Entities. The combined company (“New Dynegy”) will have nearly 20,000 MW of generating capacity. Upon completion of the Merger Agreement, which is subject to the affirmative vote of holders of at least two-thirds of our Class A common stock and the satisfaction of other conditions, the combined company will own 29 operating power plants in 13 states (excludes the 351 MW Calcasieu generation facility which we have agreed to sell to Entergy Gulf States, Inc. (“Entergy”) employing a balanced mix of fuel sources with baseload, intermediate, and peaking dispatch capabilities, greater cash flow-generating opportunity than Dynegy alone, and significant scale and scope in three key geographic regions. The expanded portfolio will also include a controlling interest in the Plum Point facility, a 665 MW coal-fired plant currently under construction in Arkansas. Additionally, the development joint venture (referred to herein as the development company) will provide us with a 50 percent ownership interest in an established growth vehicle. The LS Entities’ current development activities include nine projects totaling more than 7,600 MW in various stages of development and approximately 2,300 MW of repowering and/or expansion opportunities.
If the transaction is consummated, the LS Entities will receive 340 million shares of New Dynegy’s Class B common stock, $100 million in cash and $275 million aggregate principal amount of notes to be issued by
New Dynegy. New Dynegy will also assume approximately $1.9 billion in net debt (debt less restricted cash and investments) from the LS Entities. Please read Note 3—Business Combinations and Acquisitions—LS Power for further discussion of the terms of the Merger Agreement as well as the proxy statement/prospectus of Dynegy Acquisition, Inc. filed with the SEC on February 13, 2007.
General
Our assets are located in the Midwest, New York, Texas, Nevada and the Southeast. Our diverse power generation facilities generate electricity by burning coal, natural gas or oil. We sell electric energy, capacity and ancillary services by various means: (i) primarily through bilateral negotiated contracts with third parties and into regional central markets and (ii) with lesser volumes through structured wholesale over-the-counter markets and directly to end-use customers.
We are currently evaluating our portfolio in anticipation of consummating the LS Power transaction with the goal of focusing on regions and markets where we will have a significant asset position. This evaluation could result in sales of assets that are not considered strategic fits within our generating fleet. Our current generating facilities are as follows:
| Facility |
Total Net Capacity |
Primary Fuel Type |
Dispatch Type |
Location |
NERC Region (ISO) | |||||
| Baldwin |
1,800 | Coal | Baseload | Baldwin, IL | SERC (MISO) | |||||
| Havana Units 1-5 |
228 | Oil | Peaking | Havana, IL | SERC (MISO) | |||||
| Unit 6 |
441 | Coal | Baseload | Havana, IL | SERC (MISO) | |||||
| Hennepin |
293 | Coal | Baseload | Hennepin, IL | SERC (MISO) | |||||
| Oglesby |
63 | Gas | Peaking | Oglesby, IL | SERC (MISO) | |||||
| Stallings |
89 | Gas | Peaking | Stallings, IL | SERC (MISO) | |||||
| Tilton |
188 | Gas | Peaking | Tilton, IL | SERC (MISO) | |||||
| Vermilion Units 1-2 |
164 | Coal/Gas | Baseload | Oakwood, IL | SERC (MISO) | |||||
| Unit 3 |
12 | Oil | Peaking | Oakwood, IL | SERC (MISO) | |||||
| Wood River Units 1-3 |
119 | Gas | Peaking | Alton, IL | SERC (MISO) | |||||
| Units 4-5 |
446 | Coal | Baseload | Alton, IL | SERC (MISO) | |||||
| Rocky Road |
330 | Gas | Peaking | East Dundee, IL | RFC (PJM) | |||||
| Riverside/ Foothills |
960 | Gas | Peaking | Louisa, KY | RFC (PJM) | |||||
| Rolling Hills |
965 | Gas | Peaking | Wilkesville, OH | RFC (PJM) | |||||
| Renaissance |
776 | Gas | Peaking | Carson City, MI | RFC (MISO) | |||||
| Bluegrass (2) |
576 | Gas | Peaking | Oldham Co., KY | SERC (LG&E) | |||||
| Total Midwest |
7,450 | |||||||||
| Independence |
1,064 | Gas | Intermediate | Scriba, NY | NPCC (NYISO) | |||||
| Roseton (3) |
1,185 | Gas/Oil | Intermediate | Newburgh, NY | NPCC (NYISO) | |||||
| Danskammer Units1-2 |
123 | Gas/Oil | Peaking | Newburgh, NY | NPCC (NYISO) | |||||
| Units 3-4 (3) |
370 | Coal/Gas/Oil | Baseload | Newburgh, NY | NPCC (NYISO) | |||||
| Total Northeast |
2,742 | |||||||||
| Calcasieu (4) |
351 | Gas | Peaking | Sulphur, LA | SERC | |||||
| Heard County |
539 | Gas | Peaking | Heard Co., GA | SERC | |||||
| Black Mountain (5) |
43 | Gas | Baseload | Las Vegas, NV | WECC | |||||
| CoGen Lyondell |
614 | Gas | Baseload | Houston, TX | ERCOT (ISO) | |||||
| Total South |
1,547 | |||||||||
| Total Fleet Capacity |
11,739 | |||||||||
Index to Financial Statements (1) Unit capacity values are based on winter capacity. (2) Effective September 1, 2006, Louisville Gas & Electric, and therefore Bluegrass, left the MISO market and resumed operation as a stand-alone control area. (3) We lease the Roseton facility and units 3 and 4 of the Danskammer 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 beginning on page 50. (4) On January 31, 2007, we entered into an agreement to sell our interest in the Calcasieu power generation facility to Entergy. Subject to regulatory approval, the transaction is expected to close in early 2008. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Calcasieu on page F-20 for further discussion. (5) We own a 50% interest in this facility and the remaining 50% interest is held by Chevron U.S.A., which we refer to as Chevron, our largest shareholder. Total output capacity of this facility is 85 MW.
We also have a CRM business which represents our legacy trading business. After the termination of the Sterlington tolling agreement on March 7, 2006, the CRM business primarily consists of the Kendall tolling agreement (excluding the Sithe toll which is in our GEN-NE segment and is an intercompany agreement), as well as our legacy gas, power and emissions trading positions. On September 14, 2006, we agreed to acquire the Kendall facility either through the planned acquisition of assets from the LS Entities or as a separate transaction. The Kendall tolling arrangement will become an intercompany obligation under our GEN-MW segment upon the closing of the transaction. We report the results of this business as a separate reportable segment.
Business “Drivers” in the Power Generation Industry
Profitability of our business is largely a function of the difference between market prices for electricity and our cost to produce electricity at our various facilities from which we sell some of our energy under longer-term contracts, either directly to our customers or through the over-the-counter wholesale energy markets. We sell the remaining production into the shorter-term and spot markets (otherwise called day-ahead and real-time markets). We also hedge a portion of the output from our facilities in the financial markets based on our perspective of market fundamentals.
Market Prices for Wholesale Power . Future market prices are driven by expectations of buyers and sellers as to the fundamental supply/demand balance, similar to many other commodity markets. 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. At times in certain markets, 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.
Summer and winter weather extremes can cause increased electricity consumption, driving up prices in affected regions. Conversely, during spring and fall when weather tends to be milder, market prices are usually less extreme.
In regions with centrally dispatched market structures (such as the Midwest and Northeast regions), all generators receive the same price for energy generated based on the price required to justify production of the last megawatt that is needed to balance supply with demand. 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 higher production costs will set the market clearing price that will be paid to all generators, 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.
Production Costs. Another 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 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 oil fueled 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 also incur operations and maintenance (O&M) costs at our facilities. We categorize these costs 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.
Emissions Allowances. Operation of our power generation facilities is subject to regulatory limitations on emissions of both sulfur dioxide (SO 2 ) and nitrogen oxide (NO X ). We are granted emissions credit allowances by regulatory bodies on an annual basis. To the extent that our inventory of emissions allowances, including those that we carry forward from earlier years, are not sufficient to allow us to operate our plants within the emissions guidelines of the various air districts, we will either purchase additional emissions credits from third parties or reduce operation of that unit. Conversely, if we have more emissions credits on hand than are required to operate our facilities, we may opportunistically sell these credits, subject to certain regulatory limitations and restrictions contained in our DMG consent decree, or hold them in inventory until they are needed. Based on current projections, we do not expect a net expenditure from the purchase and sale of emissions allowances in the near term. Please read “Regulatory and Environmental Matters—Environmental, Health and Safety Matters—Multi-Pollutant Air Emission Initiatives” beginning on page 16 for a discussion of regulatory initiatives that will impact emissions over the longer term.
Services Provided. We sell electric energy, capacity and ancillary services from our facilities. Energy is the actual output of electricity that is measured in MWh at the wholesale level and is usually measured in KWh at the retail level. The capacity of a generation facility is its electricity production capability, measured in MW. Each NERC region must have sufficient generating capacity to meet expected consumption of electricity (known as load). Each NERC region calculates a reserve requirement, which is additional necessary capacity that a region must have in order to manage potential unit outages. Electricity consumers will, for reliability or regulatory reasons, contract for capacity from a capacity supplier from one or more of the generating units that the supplier owns. Ancillary services are the products of a generation facility that support the transmission grid operation, allow generation to follow real-time changes in load, and provide emergency reserves for major changes to the balance of generation and load.
We sell these components of electricity to our customers under short-term or long-term contractual agreements or tariffs. Most of the energy and capacity transactions that we enter into are based on industry standard contracts. We also sell into central markets operated by RTOs and ISOs. We enter into negotiated contracts for each product or a combination of products with other customers as well.
Customers. Our customers include RTOs and ISOs, integrated utilities, municipalities, electric cooperatives, transmission and distribution utilities, industrial customers, power marketers, banks, hedge funds, other power generators and commercial end-users. We sell electric energy, capacity and ancillary services to some or all of these customers for various lengths of time. Some of our customers, such as municipalities or integrated utilities, purchase our products in order to serve their retail, commercial and industrial customers. Other customers, such as some power marketers, may buy from us to serve load or may purchase power as a hedge against other power sales that they have made, such that they are effectively a “middle man” between generators and end-users.
Dispatch Type. Our generation assets include baseload, peaking and intermediate dispatch types. 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%-90% of the hours in a given year. Intermediate generation is not
as efficient and/or economic as baseload generation but is intended to dispatch to serve load 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. Our intermediate and peaking facilities are fueled by fuel oil or natural gas.
Capital Expenditures. 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. In 2006, we had approximately $148 million in capital expenditures for our entire fleet of generation assets, of which $90 million was for capital maintenance projects, $2 million was for development projects, primarily for the conversion of our Vermilion facility to PRB coal, and $56 million was for other environmental expenditures.
NERC Regions, RTOs and ISOs. In discussing our business, we often refer to NERC regions. The North American Electric Reliability Council (NERC) and its eight regional reliability councils (as of December 31, 2006) were formed to ensure the reliability and security of the electricity system. The regional reliability councils set standards for reliable operation and maintenance of power generation facilities and transmission systems. NERC reports seasonally and annually on generation and transmission status in each region.
Separately, RTOs and ISOs centrally operate markets and transmission across a regional footprint in some of the markets in which we operate. They are responsible for secure dispatch of all generation facilities in that footprint, and are responsible for both maximum utilization and efficiency of the transmission system within what have been determined to be secure levels. RTOs and ISOs administer electricity markets for physical and financial energy markets in the short term, usually day ahead and real-time 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.
NERC Regions as of December 31, 2006
Reliability. We seek to operate and maintain our generation fleet efficiently and safely, with an eye toward future maintenance and improvements, resulting in increased reliability. This increased reliability impacts our results to the extent that our generation units are available during times that it is economically sound to run. These efforts are reflected not only in capital improvements, but also in organizational and program changes.
Regulatory & Legislative Considerations
Our business is subject to extensive federal, state and local laws and regulations governing the generation and sale of electricity, the discharge of materials into the environment and otherwise relating to environmental, health and safety. Following is a summary of key regulatory and environmental considerations impacting our power generation operations. Please read “—Regulatory and Environmental Matters” beginning on page 15 for further discussion of the environmental and regulatory restrictions applicable to our business.
Rates. Our wholesale power sales are governed by the FERC. With the exception of CoGen Lyondell and Black Mountain, which are Qualifying Facilities (QFs), all of our facilities currently have the authority to charge market-based rates for wholesale power. Many of our facilities also have cost-based tariffs for providing reactive power support. We are subject to FERC’s regulations governing market behavior and prohibiting market manipulation, the violation of which could result in the revocation or suspension of our market-based rate authority as well as refunds, disgorgement of profits and monetary penalties.
Market Structure. Our sales of electricity and related services to particular customers and/or at a particular price are subject to the market structure and related rules in the states or regions where we operate. For instance, in organized markets like Texas, bids and prices are capped, and in the New York market, there is a price mitigation procedure to correct the adverse impact of errors or other activities outside the bounds of market rules and policies. In the state of Illinois, a resource procurement auction was recently conducted, resulting in the award of binding contracts between the utilities and wholesale energy providers such as Dynegy.
SO 2 and NO X Emissions. The Clean Air Act and comparable state laws and regulations require that specified reductions in SO 2 and NO X emissions be achieved. More recent regulations, including the Clean Air Interstate Rule (CAIR), require significant emissions reductions over the next several years. We have expended capital and installed emission control equipment at a number of our facilities to meet current requirements and expect to expend significant additional capital in the future to satisfy prospective requirements.
Mercury Emissions. The Clean Air Mercury Rule (CAMR), issued by the EPA in March 2005, requires that specified reductions in mercury emissions be achieved from the air emissions of coal-fired power plants. States are required to adopt the federal CAMR or a state rule meeting its minimum requirements. Both the states of Illinois and New York, where we have significant coal-fired assets, have recently adopted more stringent rules that will require greater reductions in emissions and thus could entail additional capital expenditures, in each case sooner than would CAMR. Our projected capital expenditures through 2013 include controls that we believe will achieve the new mercury emission reduction requirements. Additional capital expenditures may be required at our Wood River facility in 2015 depending on the performance of equipment installed between now and then.
Water Withdrawals. The Clean Water Act and comparable state laws and regulations require that the location, design, construction and capacity of cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. The cooling water intake structures at four of our coal plants and one of our fuel oil plants in Illinois and New York are subject to this requirement. The scope of the requirement and the compliance methodologies allowed may become more restrictive, resulting in potentially significant increased costs. In addition, the timing for compliance may be adjusted.
Carbon Emissions. Our Northeast assets may become subject to a state-driven greenhouse gas emission reduction program known as the Regional Greenhouse Gas Initiative (RGGI). RGGI is a program under development by nine New England and Mid-Atlantic states to reduce carbon dioxide emissions from power
plants. The state of New York has introduced, as a “pre-proposal”, a rule which would require affected generators to purchase 100 percent of the carbon credits needed to operate their facilities through an auction process. The final program requirements of RGGI and subsequent impact to our operations are not known at this time. The Northeast states currently intend to finalize carbon dioxide emissions requirements for electric generating facilities during 2007, with implementation to begin in 2009. Additional regulations are under consideration by various policy-making bodies and, if adopted, could impact our operations and require additional capital expenditures. Please read Note 18—Regulatory Issues on page F-53 for further discussion.
SEGMENT DISCUSSION
