Item 1. Business
THE COMPANY
We are a holding company and conduct substantially all of our business operations through our subsidiaries. We own operating divisions engaged in power generation and natural gas liquids. Through these operating divisions, we serve customers by delivering value-added solutions to meet their energy needs.
We are in the process of restructuring our company in response to events that have negatively impacted the merchant energy industry, and our company in particular, over the past year. This restructuring includes significant changes in our operations, primarily our exit from third-party risk management aspects of the marketing and trading business. Our restructuring also includes significant financial transactions that have stabilized our liquidity position and began the process of decreasing our substantial financial leverage. Significant accomplishments include the following:
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The sale of Northern Natural Gas Company;
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The sale of our U.K. natural gas storage business;
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The sale of our global liquids business;
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Major progress towards our exit from the third-party marketing and trading, or customer risk management business, including the completion of our exit from European marketing and trading and the transition of ChevronTexaco Corporation’s natural gas marketing business back to ChevronTexaco, and the reduction in associated collateral requirements;
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The extension of the maturity of our two primary bank credit facilities until February 2005; and
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Considerable workforce reductions, which we expect will provide substantial general and administrative cost savings.
In our new, simplified operating structure, we intend to focus on being a low-cost producer of physical products and provider of services in each of our two main operating divisions. Our results also will continue to reflect our customer risk management business, until the remaining obligations associated with this business have been satisfied or restructured.
We are a wholly owned subsidiary of Dynegy Inc., which began operations in 1985. Dynegy Inc. acquired Illinova Corporation (“Illinova”) in the first quarter of 2000. As part of the acquisition of Illinova, the former Dynegy Inc., which was renamed Dynegy Holdings Inc., became a wholly owned subsidiary of a new holding company, Dynegy Inc. The assets, liabilities and operations of the former Dynegy Inc. before the acquisition became the assets, liabilities and operations of Dynegy Holdings Inc. after the acquisition.
At the end of September 2000, Dynegy Inc. contributed Dynegy Midwest Generation (“DMG”) to us. DMG owns and operates the fossil fuel generating assets formerly held by IP, a wholly owned subsidiary of Illinova. The net contribution of approximately $2.2 billion was accounted for in a manner similar to a pooling of interests. As a result, DMG’s results of operations are reflected in our results of operations for all of 2000 and thereafter.
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.
Our SEC filings on Forms 10-K, 10-Q and 8-K (and amendments to such filings) are available free of charge on our website, 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.
SEGMENT DISCUSSION
Beginning in 2003, we will report the financial results of the following three business segments:
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Power generation;
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Natural gas liquids; and
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Customer risk management.
Other reported results will include corporate overhead and related results. Set forth below is a discussion of each of our new business segments.
We have reported our historical segment results in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 29 of this Form 10-K based on our 2002 business segments-Wholesale Energy Network, Dynegy Midstream Services and Transmission and Distribution. As described below, the power generation operations previously included in the Wholesale Energy Network segment will now comprise the Power Generation segment. The Wholesale Energy Network segment’s other former operations, to the extent such operations continue, will comprise the Customer Risk Management segment. The “Other” category will include corporate general and administrative expenses, income taxes and corporate interest expenses, all of which we previously allocated among our operating divisions. The natural gas liquids operations that previously comprised our Dynegy Midstream Services segment will continue to be reported as its own segment. The Transmission and Distribution segment included the results of Northern Natural during the period that we owned the company in 2002.
Power Generation
We own or lease electric power generation facilities with an aggregate net generating capacity of 13,167 MW located in six regions of the United States, including one facility nearing completion of construction with approximately 800 MW of net generating capacity. The following table describes our current generation facilities by name, region, location, net capacity, fuel and dispatch type.
REGIONAL SUMMARY OF OUR U.S. GENERATION FACILITIES(1)
(AS OF DECEMBER 31, 2002)
(1)
We own 100% of each unit listed except as otherwise indicated.
(2)
We lease this facility pursuant to an off-balance sheet lease arrangement that is further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Off-Balance Sheet Arrangements” beginning on page .
(3)
We own a 50% interest in this facility.
(4)
We own a 20% interest in this facility.
(5)
This facility is under construction, with completion expected in the second quarter 2003.
(6)
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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Off-Balance Sheet Arrangements” beginning on page .
(7)
We own a 5% interest in this facility.
(8)
We own a 50% interest in each of these facilities through West Coast Power, L.L.C., a joint venture with NRG Energy.
(9)
We own a 50% interest in this facility through a joint venture with ChevronTexaco.
(10)
We shut these units down at the end of 2002 because we deemed them no longer commercially viable.
(11)
We own a 16% interest in this facility.
(12)
We own a 10% interest in this facility.
Midwest region-Mid-America Interconnected Network Reliability Council (MAIN). At December 31, 2002, we owned or leased interests in ten generating facilities with an aggregate net generating capacity of 4,212 MW located in Illinois within the MAIN reliability area. Eight of these facilities, which we acquired as a result of the Illinova acquisition in February 2000, are currently owned by Dynegy Midwest Generation, Inc., one of our indirect subsidiaries. DMG pledged these facilities as collateral in connection with a July 2002 amendment to our Black Thunder financing. Please read Item 8, Financial Statements and Supplementary Data, Note 10-Debt beginning on page for further discussion of this financing. We hold one of these facilities, the Tilton facility, through an off-balance sheet lease arrangement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Off-Balance Sheet Arrangements” beginning on page 40 for further discussion of this arrangement. The generating capacity of the MAIN facilities is approximately 80% baseload and 20% peaking and represents approximately 6% of the generating capacity within the MAIN region. The baseload capacity is primarily fueled by coal, with some ability to fire gas, while the remainder is primarily fueled by natural gas and oil.
DMG has a power purchase agreement with IP that provides the regulated utility with approximately 70% of its capacity requirements through December 2004. The contract provides for fixed capacity payments based on the megawatt capacity reserved. DMG also receives variable energy payments for each MW-hour of energy delivered under the contract based on DMG’s cost of generation. As part of the power purchase agreement, DMG also supplies all ancillary services necessary for IP to serve its load and provide transmission services to its customers. The IP power purchase agreement provided a substantial portion of the operating income from our power generation business in 2002. DMG is not the sole supplier to IP, but bears ultimate responsibility for serving the load as the provider of last resort. The eight facilities that primarily provide the power under this agreement were formerly owned by IP and are in locations that are best suited for serving IP’s native load.
In addition to the IP contract, the Rocky Road facility’s 168 MW of peaking capacity is under long-term contract with another purchaser through May 2009. The contract is a tolling arrangement pursuant to which the facility receives fixed monthly payments and a variable fee based on the power that it actually generates.
Approximately 50% of the energy generated by our Illinois facilities is sold pursuant to the long-term contracts described above. The remainder of the power generated is sold primarily into wholesale markets in MAIN, the neighboring East Central Reliability Area, or ECAR, and the Pennsylvania-New Jersey-Maryland market, or PJM. The MAIN market includes all or portions of the states of Illinois, Wisconsin and Missouri. The ECAR market includes all or portions of the states of Indiana, Ohio, Michigan, Virginia, West Virginia, Tennessee, Maryland and Pennsylvania. MAIN and ECAR, like the rest of the country, are currently in a state of regulatory transition as each transmission provider in this region seeks to join regional transmission organizations, or RTOs, that operate the transmission system on a regional basis. Additionally, the RTOs implement the rules and requirements for competitive wholesale markets as set forth by the FERC. The Midwest Independent System Operator, or MISO, has been approved by the FERC to administer a substantial portion of the transmission facilities in this region, while PJM, another FERC-approved independent system operator, has been approved to administer other portions of the region. However, because state and federal regulators must approve these transfers, the timing for transmission providers to turn over control of their high-voltage power lines to the RTOs remains uncertain. State and federal regulators must approve the transfers, and states, such as
Both the MISO and PJM continue to move forward with integrating those transmission facilities that have been approved for transfer to the RTOs, and are developing a plan to have a common energy market across their respective control areas by late 2005 or early 2006.
PJM manages the transmission system and maintains competitive wholesale markets within its region. PJM historically covered the states of Pennsylvania, New Jersey and Maryland, but is poised to cover a larger geographic area as some midwestern companies seek to join the RTO. PJM operates the transmission grid for reliability purposes as well as managing the market for firm transmission rights, or FTRs, that determine the economics of congestion on the transmission system. Under a locational marginal pricing methodology, or LMP, PJM facilitates the competitive wholesale spot energy markets, which set the prices at which energy is bought and sold. It is also responsible for ensuring that adequate capacity is available for secure operations of the region, and it provides a capacity auction to facilitate this market. Much of the FERC’s proposed Standard Market Design rulemaking utilizes the market structure for energy, transmission and capacity that PJM has implemented over the past few years. As mentioned above, PJM and MISO are seeking common energy markets that will be based on the LMP method of establishing prices at location; additionally, they plan to use similar FTRs and capacity markets.
We currently sell power from our facilities in the MAIN region to customers under short-term and long-term agreements. Many of the longer agreements are bilateral contracts that are generally non-standard with highly negotiated terms and conditions, while short-term sales usually occur through well-established existing commercial relationships. Our customers include municipalities, electric cooperatives, integrated utilities, transmission and distribution utilities, industrial customers and power marketers. Some states within this region have restructured their electric power markets to competitive retail markets from traditional utility monopoly markets, which allow us to sell directly to retail and commercial end-users.
Midwest region-ECAR. We own or lease interests in six generating facilities with an aggregate net generating capacity of 2,912 MW located in the states of Kentucky, Michigan and Ohio. One of these facilities, the Rolling Hills facility, is currently under construction with commercial operation expected to begin in the second quarter 2003. The Riverside facility is leased by one of our indirect subsidiaries, Riverside Generating Company, L.L.C. In addition, the Renaissance and Rolling Hills facilities are pledged as collateral to secure a financing originated in June 2002. Please read Item 8, Financial Statements and Supplementary Data, Note 10-Debt beginning on page for further discussion of this financing. The generating capacity of the ECAR facilities is approximately 2% baseload and 98% peaking and represents approximately 2% of the generating capacity within the ECAR region. All units within the region are fueled by natural gas.
The majority of the power generated by our ECAR facilities is sold to wholesale customers in the MAIN, PJM and ECAR markets. Please read “-Midwest region-Mid-America Interconnected Network Reliability Council (MAIN)” above for a discussion of these markets. All 62 MW of baseload capacity, representing our net ownership interest in the Michigan Power facility, is under contract through December 2030.
Northeast region. At December 31, 2002, we owned or leased two generating facilities with an aggregate net generating capacity of 1,700 MW located in Newburgh, New York, 50 miles north of New York City. These facilities, acquired from Central Hudson Gas & Electric Corporation, Consolidated Edison Company of New York, Inc. and Niagara Mohawk Power Corporation in January 2001, are referred to as the Dynegy Northeast Generation (DNE) facilities. The Danskammer facility has four generating units, two of which are owned and two of which are leased by one of our indirect subsidiaries, Dynegy Danskammer, L.L.C. The Roseton facility has two generating units, each of which is leased by another of our indirect subsidiaries, Dynegy Roseton, L.L.C. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Off-Balance Sheet Arrangements” beginning on page 40 for further discussion of this off-balance sheet lease arrangement.
The generating capacity of these facilities represents approximately 5% of the generating capacity in the state of New York. Two of the Danskammer units use natural gas or fuel oil, while the other two Danskammer
units are capable of burning both coal and natural gas. The two Roseton units are capable of burning fuel oil or natural gas or both simultaneously. The facilities’ sites are adjacent and share common resources such as fuel handling, a docking terminal, personnel and systems.
We currently sell approximately 23% of the capacity from our DNE facilities to Central Hudson pursuant to a transitional power purchase agreement that expires in October 2004. We sell the remainder of the power generated by these facilities into the New York wholesale market, which is described below. We sell energy and ancillary services into both day ahead and real-time sales markets, and we sell capacity and energy forward (up to 1.5 years for capacity and 3 years for energy). Our customers include the members of the New York Independent System Operator, or NYISO, including municipalities, electric cooperatives, integrated utilities, transmission and distribution utilities, retail electric providers and power marketers. We sell energy products to wholesale, commercial and industrial customers in New York under negotiated bilateral contracts. We also export power to neighboring regions, including PJM, Ontario and New England.
The New York wholesale market operates as a centralized power pool administered by the NYISO. Although the transmission infrastructure within this market is generally well developed and independently operated, significant transmission constraints exist. In particular, there is limited transmission capability from western New York to eastern New York and into New York City. Depending on the timing and nature of transmission constraints, market prices may vary between sub-regions of the market. For example, as a result of transmission constraints into eastern New York and New York City, power prices are generally higher in these areas than in other parts of the state. An unforced capacity market, or UCAP, has been established by the NYISO designed to ensure that there is enough generation capacity to meet retail energy demand and ancillary services requirements. All power retailers are required to demonstrate commitments for capacity sufficient to meet their forecast peak load plus a reserve requirement, currently set at 18 percent.
In addition to managing the transmission system, the NYISO is responsible for maintaining competitive wholesale markets, operating the day ahead, real time, ancillary service and UCAP markets and determining the market clearing price based on bids submitted by participating generators. The NYISO matches sellers with buyers within New York that meet specified minimum credit standards. The NYISO has protocols that provide the structure, rules and pricing mechanisms for various energy products and maintains FERC-approved rates, terms and conditions for transmission service in its control area. NYISO protocols allow energy demand, commonly referred to as “load,” to respond to high prices in emergency and non-emergency situations. The lack of programs, however, to implement load response to prices has been cited as one of the primary reasons for retaining wholesale energy bid caps, which are currently set at $1,000 per megawatt hour. Lower price caps are utilized in other regions.
The New York market is subject to significant regulatory oversight and control. Our operating results may be adversely affected by changes to the current regulatory structure. For additional discussion of the impact of current regulations on the New York market, please read “-Regulation” beginning on page 19.
Southeast region-Southeast Electric Reliability Council (SERC). At December 31, 2002, we owned interests in five generating facilities with an aggregate net generating capacity of 1,961 MW located in the states of Georgia, Louisiana, North Carolina and Virginia. This capacity’s primary fuel is natural gas, with some capability to burn fuel oil.
320 MW of the SERC capacity is under long-term contracts. A contract for the Commonwealth facility’s 170 MW of capacity expires in May 2017, while a contract for the Hartwell facility’s 150 MW of capacity expires in May 2019. The remainder of the power generated by our SERC facilities is generally sold to wholesale customers in the SERC market. This market includes all or portions of the states of Missouri, Kentucky, Arkansas, Tennessee, West Virginia, Virginia, North Carolina, South Carolina, Texas, Louisiana, Mississippi, Alabama, Georgia and Florida. There are several proposals to establish RTOs that would define the rules and requirements around which competitive wholesale markets in this region would develop. The FERC has provisionally approved proposals by SeTrans Grid Company L.L.C. and GridSouth Transco L.L.C. to administer
a substantial portion of the transmission facilities in this region. As a result, the final market structure for this region remains uncertain. Currently, the transmission infrastructure in this market is generally owned and managed by integrated utilities, some of which are our competitors. As a result, market anomalies may exist. Transmission constraints are present in this market. Transmission infrastructure owners are subject to tariffs and protocols administered by the FERC.
We currently sell power from our facilities in this region to customers under short-term and long-term agreements. Many of the longer agreements are bilateral contracts that are generally non-standard with highly negotiated terms and conditions, while short-term sales usually occur through well-established existing commercial relationships. Our customers include municipalities, electric cooperatives, integrated utilities, transmission and distribution utilities and power marketers. To date, there has been no significant access granted to retail customers in SERC.
West region-Western Electricity Coordinating Council (WECC). At December 31, 2002, we owned interests in six generating facilities with an aggregate net generating capacity of 1,440 MW located in the states of California, Nevada and Washington. The generating capacity of our WECC facilities is approximately 4% baseload, 69% intermediate and 27% peaking capacity and represents less than 1% of the generating capacity in the WECC region. This capacity is largely natural gas-fired, although two of the peaking facilities located in California can also burn fuel oil.
Of our 1,440 MW of net generating capacity in the WECC, 1,385 MW consists of our 50 percent share of the 2,770 MW portfolio of facilities owned by West Coast Power, L.L.C., a joint venture between Dynegy and NRG Energy. All of West Coast Power’s facilities are located in southern California and the generation output of the facilities is substantially covered by a contract between one of our marketing subsidiaries, as agent for the facility owners, and the California Department of Water Resources, referred to as the CDWR, which expires in December 2004. The agreement provides for a firm commitment of 600 MW of on-peak capacity and 200 MW of off-peak capacity, in each case at a fixed price. The agreement also contains a contingent component pursuant to which the CDWR can elect to reserve up to an additional 1,500 MW of on-peak capacity and 1,500 MW of off-peak capacity, subject to required minimum reservation amounts of 500 MW and 200 MW, respectively. We receive a fixed capacity payment for any contingent amounts reserved as well as payments for contingent energy actually sold, which energy payments are based on fuel, operating and maintenance and start-up costs. We may also market the energy, capacity and ancillary services output of these facilities through bilateral contracts or sell into the markets operated by the California Independent System Operator, or Cal ISO. Please read the discussion of the California electricity market below as well as Item 8, Financial Statements and Supplementary Data, Note 14-Commitments and Contingencies beginning on page for a discussion of the ongoing legal challenges to the CDWR contract. West Coast Power shut down two units at these facilities, representing an aggregate capacity of 209 MW, at the end of 2002 because we deemed them no longer commercially viable.
Approximately 55 MW of baseload capacity outside of California consists of our equity interests in QFs facilities that are under long-term contracts. Of this capacity, the Ferndale facility’s 12 MW of capacity is contracted through December 2011 and the Black Mountain facility’s 43 MW of capacity is contracted through April 2023.
The WECC regional market includes all or parts of the states of Arizona, California, Oregon, Nevada, New Mexico, Colorado, Wyoming, Idaho, Montana, Texas, South Dakota, Utah and Washington. Generally, we sell the power generated by facilities that are not under long-term contracts to customers located in southern California. Our customers include power marketers, investor-owned utilities, electric cooperatives, municipal utilities and the Cal ISO, acting on behalf of load-serving entities. We sell power and ancillary services to these customers through a combination of bilateral contracts and sales made in the Cal ISO’s day-ahead and hour- ahead ancillary services markets and its real-time energy market. Many of the longer agreements we enter into are bilateral contracts that are generally non-standard with highly negotiated terms and conditions, while short-term sales usually occur through well-established existing commercial relationships. Access to retail customers has been substantially curtailed in this region.
Our operations in the California market are subject to numerous environmental and other regulatory restrictions. Permits issued by local air districts restrict the output of some of our generating facilities. In addition, certain air districts require us to purchase emission credits to offset nitrogen oxide emissions from our facilities.
In 1996 and 1997, the FERC issued a series of orders approving a wholesale market structure. This structure was administered by two independent non-profit corporations: the Cal ISO, responsible for operational control of the transmission system and balancing actual supply and demand in “real-time,” and the Cal PX, responsible for conducting auctions for the purchase or sale of electricity on a day-ahead or day-of basis. As part of this market restructuring, California’s distribution utilities sold essentially all of their gas-fired plants to third parties. The utilities were required to sell their remaining generation into the Cal PX markets and purchase all of their power requirements from the Cal PX markets at market-based rates approved by the FERC. The Cal PX ceased operations in January 2001 and subsequently filed for bankruptcy. The Cal ISO currently is conducting a major market redesign process that, if approved by the FERC, could change the structure of the markets operated by the Cal ISO, including changes to market monitoring and mitigation, congestion management and capacity obligations. For a discussion of litigation and other legal proceedings related to energy market restructuring in California, the impact of current regulations on our WECC facilities and related uncertainty associated with the California wholesale market, please read “-Regulation” beginning on page 19 and Item 8, Financial Statements and Supplementary Data, Note 14-Commitments and Contingencies beginning on page.
Texas region-Electric Reliability Council of Texas (ERCOT). At December 31, 2002, we owned or leased interests in four generating facilities with an aggregate net generating capacity of 942 MW located in Texas. The CoGen Lyondell facility is leased by one of our indirect subsidiaries, CoGen Lyondell, Inc. The generating capacity of our ERCOT facilities consists entirely of baseload facilities and represents approximately 1% of the generating capacity in the ERCOT region. All facilities are fueled by natural gas.
Approximately 305 MW of baseload capacity in this region is under long-term contracts. The Paris facility’s 37 MW of capacity is contracted through September 2005, 185 MW of the Oyster Creek facility’s capacity is contracted through October 2014 and the Frontier facility’s 83 MW of capacity is contracted through September 2020.
The ERCOT region is comprised of the majority of the state of Texas. As part of the transition to deregulation in Texas, ERCOT changed its operations from 10 control areas, managed by utilities in the state, to a single control area on July 31, 2001. ERCOT, as the independent system operator, is responsible for maintaining reliable operations of the bulk electric power supply system in the ERCOT market. It is responsible for facilitating information needed for retail customer choice. It ensures that electricity production and delivery are accurately accounted for among the generation resources and wholesale participants in the ERCOT market. Unlike independent systems operators in other regions of the country, ERCOT does not centrally dispatch resources in the region. Market participants are generally responsible for contracting for their requirements bilaterally. However, ERCOT does procure energy on behalf of market participants pursuant to relaxed Balanced Schedule Protocols implemented on November 1, 2002. ERCOT also serves as agent for procuring ancillary services for those who elect not to provide their own requirements.
Members of ERCOT include retail customers, investor and municipal owned electric utilities, rural electric cooperatives, river authorities, independent generators, power marketers and retail electric providers. The ERCOT market operates under the reliability standards set by the North American Electric Reliability Council. Unlike other regions of the U.S., the Public Utility Commission of Texas, or PUCT, has primary jurisdictional authority over the ERCOT market, rather than the FERC. Currently, the PUCT is evaluating the need to change ERCOT’s market structure due to a variety of commercial and operational issues that have been uncovered in the first 18 months of operation. The market design rulemaking proceeding is expected to conclude during the first half of 2003. Implementation of market redesign would follow.
We currently sell power from our facilities in this region to customers under short-term and long-term agreements. Many of the longer agreements are bilateral contracts that are generally non-standard with highly negotiated terms and conditions, while short-term sales usually occur through well-established existing commercial relationships. Our customers include municipalities and electric cooperatives, which remain primarily integrated utilities, power marketers and retail electric providers. We also sell directly to commercial and industrial end users.
Retail Supply Business. We selectively contract with individual commercial and industrial customers to serve their load requirements in markets where we have a generation presence and where the regulatory environment supports these efforts. Our current marketing operations are directed towards Texas, Illinois and New York. We also have four contracts with The Kroger Co. to provide it with an aggregate of 100 MW of capacity in California. These contracts, which were executed by the parties during the first half of 2001, have terms of varying lengths, the longest of which extends through December 2006. Concurrently with our execution of these contracts, we entered into other contracts to provide us with the power supply to support our obligations to The Kroger Co. Please read Item 8, Financial Statements and Supplementary Data, Note 14-Commitments and Contingencies beginning on page for discussion of The Kroger Co.’s legal challenges to these four contracts.
Power Generation Segment Marketing and Trading Strategy. As previously announced, we are in the process of exiting third-party risk management aspects of the marketing and trading business. Please read “-Customer Risk Management Segment” beginning on page 16 for further discussion of this exit. Our power generation segment will continue to manage price risk through the optimization of fuel procurement and the marketing of power generated from its owned and controlled assets. As part of our commercial strategy to optimize these assets (including agency and energy management agreements to which we are a party) and mitigating any associated risk, we will enter into various financial and other transactions and instruments, including entering into and unwinding forward hedges related to our generating capacity. We may also purchase capacity and energy to serve more efficiently our supply obligations under various contracts in each of the regions in which we operate.
Natural Gas Liquids
Our natural gas liquids segment primarily consists of our midstream asset operations, located principally in Texas, Louisiana and New Mexico, and our North American NGL marketing business. This segment has both upstream and downstream components. The upstream components include natural gas gathering and processing, while the downstream components include fractionating, storing, terminalling, transporting, distributing and marketing NGLs. We generate commodity and fee-based revenue in our upstream activities; we generate fee-based revenue downstream at our fractionation, storage, terminalling and distribution facilities; and we generate margin and commodity-based revenue in our NGL distribution and marketing operations.
The following graphic depicts the fee opportunities that exist throughout our upstream and downstream operations.
Upstream business. Our upstream business comprises our natural gas gathering and processing operations. Natural gas processing includes the operations of refining raw natural gas into merchantable pipeline-quality natural gas by extracting NGLs and removing impurities. We own interests in 20 gas processing plants, including 12 plants we operate. We also operate 9,188 miles of natural gas gathering pipeline systems associated with the 12 operated facilities and 2 stand-alone gas gathering pipeline systems where gas is treated and/or processed at third-party plants. These assets are located in key producing areas of Louisiana, New Mexico and Texas. During 2002, we processed an average of 2.1 Bcf/d of natural gas and produced an average of 92,000 gross barrels per day of NGLs. We are also party to processing agreements with four third-party plants.
Our natural gas processing services are provided in two types of plant categories: field plants and straddle plants. Field plants aggregate volumes of unprocessed gas from multiple onshore producing wells through gathering systems. These volumes are aggregated into economically sufficient volumes to be processed to extract NGLs and to remove water vapor, solids and other contaminants. Straddle plants generally are situated on mainline natural gas pipelines. Our straddle plants are located on pipelines transporting natural gas from the Gulf of Mexico to natural gas markets.
Our upstream assets are located in the high-growth oil and gas exploration and production areas of North Texas and Louisiana and the mature Permian basin. The following map depicts our upstream assets in their current locations, including our capacity, throughput and production levels by region.
We process natural gas under several types of contracts. Under “percentage of liquids” contracts, the producer delivers to us a percentage of the NGLs as our fee and retains the value of all remaining NGLs and natural gas at the processing plant tailgate. Under “percentage of proceeds” contracts, a producer delivers to us a percentage of the NGLs and a percentage of the natural gas as payment for our services and retains the value of the remaining NGLs and natural gas at the tailgate of the processing plant. Under both “percentage of liquids” and “percentage of proceeds” contracts, the producer will either take their share of the NGLs and natural gas in kind or have us sell the commodities and return the sale proceeds to them.
Under “keep-whole” processing arrangements, we extract NGLs and return to the producer volumes of merchantable natural gas containing the same Btu content as the unprocessed natural gas that was delivered to us for processing. We retain the NGLs as our fee for processing and must purchase and return to the producer sufficient volumes of merchantable natural gas to replace the Btus that were removed through processing so that the producer is “kept whole.”
Under “economic election” contracts, when processing economics are unfavorable the producer generally has the election to either bypass the plant or pay us a per-unit fee to process the gas. In some of the more recent agreements, the election is automatic, depending on processing economics. In this situation, when the value of the NGLs is less than the value of gas on an equivalent Btu basis, the contract automatically converts to a fee-based processing arrangement. In both instances, this fee could be in the form of a percentage of the natural gas and/or NGLs processed or in cash. Under “wellhead purchase” contracts, we purchase unprocessed natural gas from a producer at the wellhead at a discount to the market value of the gas. This discount is our margin for gathering and processing.
In 2003, we estimate that approximately
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56% of the volumes we process will be under percentage of liquids arrangements;
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19% of the volumes will be under percentage of proceeds contracts;
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15% of the volumes will be under keep-whole contracts;
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9% of the volumes will be under economic election contracts; and
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the remaining 1% will be under wellhead purchase contracts.
Pursuant to agreements we have with ChevronTexaco, we have the right to process substantially all of ChevronTexaco’s gas in North America. Generally, with respect to gas produced from all areas other than the Gulf of Mexico, we process the gas in field processing plants owned by us or owned by third parties. The gas processed in our field plants is processed on a percentage of proceeds basis and is based on a commitment of such production by ChevronTexaco for the life of the oil, gas and/or mineral lease from which the production is obtained. With respect to the gas produced from the Gulf of Mexico area, ChevronTexaco’s gas is processed in straddle plants in which we own an interest and in plants owned by third parties. The gas produced from the Gulf of Mexico area is processed on a percentage of liquids basis when processing is economical or is processed on a fee basis if processing is uneconomical. The oil, gas and/or mineral leases committed under this agreement are committed for the life of the prospect.
Both types of processing agreements with ChevronTexaco, our field processing agreements and our Gulf of Mexico processing agreement, allow either party to renegotiate the commercial terms effective as of September 1, 2006 and on each successive ten-year period thereafter, for ChevronTexaco gas processed in field processing plants, and five years thereafter, for gas produced from the Gulf of Mexico and processed in Louisiana straddle plants. These renegotiations are to assure that commercial terms are substantially similar to those which, as of the date of the renegotiation, each party could expect to obtain in a freely negotiated processing agreement providing for a commitment of gas of similar quantity and quality for a ten-year term, with respect to the field plants, and a life-of-lease commitment, with respect to the straddle plants. During 2002 and 2001, respectively, ChevronTexaco gas accounted for 27% and 22% of the total volume of gas we processed.
Downstream business. In our downstream business, we use our integrated assets to fractionate, store, terminal, transport, distribute and market NGLs. Our downstream assets are generally connected to and supplied by our upstream assets and are located in Mont Belvieu, Texas, the hub of the U.S. NGL business, and West Louisiana. The following map depicts our downstream assets in their current locations, including our capacity and throughput capabilities.
Fractionation. When pipeline-quality natural gas is separated from NGLs at processing plants, the NGLs are generally in the form of a commingled stream of light liquid hydrocarbons, which is referred to as “mixed” or “raw” NGLs. The mixed NGLs are separated at fractionation facilities through distillation into the following component products:
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ethane, or a mixture of ethane and propane known as EP mix;
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propane;
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normal butane;
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isobutane; and
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natural gasoline.
We fractionate volumes for customers, from both our own upstream operations and third parties, pursuant to contracts that typically include a base fee per gallon and other components that are subject to adjustment for variable costs such as energy consumed in fractionation. We have ownership interests in three stand-alone fractionation facilities that are strategically located on the Texas and Louisiana Gulf Coast. We operate two of the facilities, one at Mont Belvieu, Texas and the other at Lake Charles, Louisiana. During 2002, these facilities fractionated an aggregate average of 215,000 gross barrels per day. We also have an equity investment in a third fractionator located in Mont Belvieu, Texas.
Storage. Our NGL storage facilities have extensive pipeline connections to third-party pipelines, third- party facilities and to our own fractionation and terminalling facilities. In addition, these storage facilities are connected to marine, rail and truck loading and unloading facilities that provide service and products to our customers. We generate fee-based revenue from our storage business by providing long-term and short-term storage services and throughput capability to affiliated and third-party domestic customers. We own and/or operate a total of 41 storage wells with an aggregate capacity of 108 MMBbls, the usage of which may be limited by brine handling capacity.
Brine is utilized to displace in the storage wells the NGLs removed from storage. When large volumes of NGLs are stored, we store the displaced brine in our brine storage ponds adjacent to our storage facilities and, depending on the volume, may inject excess brine in our brine disposal well. When reduced volumes of NGLs are stored, we utilize the brine from our brine storage ponds to displace the volumes of NGLs removed and, if necessary, can produce additional brine from wells dedicated for that purpose through a process known as brine leaching.
Transportation and Logistics. Our NGL transportation and logistics infrastructure is made up of a wide range of transportation and distribution assets supporting the delivery requirements of our distribution and marketing business. These assets are deployed to serve our wholesale distribution terminals, fractionation facilities, underground storage facilities, pipeline injection terminals and many of the nation’s crude oil refineries. Our marine terminals, located in Texas, Florida, Mississippi and Tennessee, offer importers and wholesalers a variety of methods for transporting products to the marketplace. Our transportation assets include:
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access to up to 2,000 railcars that we manage pursuant to a services agreement with ChevronTexaco;
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87 transport tractors and 114 tank trailers;
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over 580 miles of gas liquids pipelines, primarily in the North Texas, Gulf Coast and Permian basin regions; and
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21 pressurized LPG barges.
We maximize use of our transportation assets by providing fee-based transportation services to refineries and petrochemical companies in the Gulf of Mexico region and to the wholesale propane marketing business nationwide.
Distribution and Marketing Services. Our distribution and marketing services include:
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refinery services;
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wholesale propane marketing; and
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purchasing mixed NGLs and NGL products from NGL producers and other sources and selling the NGL products to petrochemical manufacturers, refineries and other marketing and retail companies.
Our refinery services business consists of providing LPG balancing services, purchasing NGL products from refinery customers and selling NGL products to various customers. In our LPG balancing operations, we use our storage, transportation, distribution and marketing assets to assist refinery customers in managing their NGL product inventories. This includes both feedstocks utilized in refining processes and excess LPGs produced by those processes. We generally earn a margin in our refinery services operations by retaining a portion of the resale price of excess NGLs or a fixed minimum fee per gallon and by charging a fee for locating and supplying feedstocks to the refinery either based on a percentage of the cost in obtaining such supply or a minimum fee per gallon. Approximately 35% and 15% of this segment’s NGL purchases in 2002 and 2001, respectively, were from ChevronTexaco. In 2002, we sold an average of 60,000 barrels per day through our refinery services business.
We have contracts with each of ChevronTexaco’s refineries situated in El Paso, Texas, El Segundo, California, Pascagoula, Mississippi, Richmond, California, Salt Lake City, Utah and Hawaii pursuant to which
we provide refinery services. All of these contracts allow us to market excess NGLs produced during the refining process. In addition, with respect to all of the refineries except Hawaii, these agreements also provide for the supply by us of NGLs to ChevronTexaco, which are utilized in its refining process. Generally, these agreements provide that we obtain on behalf of the refineries any such NGL feedstocks that they need and, in return, we are reimbursed for the cost of acquiring such feedstocks and are paid a cents-per-gallon fee for providing such services. These agreements extend through August 2006.
Our wholesale propane marketing operations include the sale of propane and related logistical services to major multi-state retailers, independent retailers and other end users. Our propane supply comes from our refinery services operations and from our other owned and/or managed distribution and marketing assets. In addition, we also have the right to purchase or market substantially all of ChevronTexaco’s NGLs (both mixed and raw) pursuant to a Master NGL Purchase Agreement that extends through August 31, 2006. We generally sell propane at a fixed or posted price at the time of delivery. In 2002, we sold an average of 40,000 barrels of propane per day. In January 2002, we purchased former Texaco’s wholesale propane marketing business and integrated it into our existing wholesale business.
We market our own NGL production and also purchase NGL products from other NGL producers and marketers for resale. In 2002, our distribution and marketing services business sold an average of 303,000 barrels per day of NGLs in North America. We generally purchase mixed NGLs from producers at a monthly pricing index less applicable fractionation, transportation and marketing fees and resell these products to petrochemical manufacturers, refineries and other marketing and retail companies. This is primarily a physical business in which we earn margins from purchasing and selling NGL products from producers under contract. We also earn margins by purchasing and reselling NGL products in the spot and forward markets.
In 2002, we marketed 96,000 barrels per day of LPG worldwide, using chartered large-hull ships. These operations consisted primarily of acquiring and marketing LPG from producing areas in the North Sea, West Africa, Algeria and the Arabian Sea, as well as from the U.S. Gulf Coast region. During the fourth quarter 2002, we decided to exit the global liquids business and sold our London-based international LPG trading and transportation business to Trammo Gas International Inc., a wholly owned subsidiary of Transammonia Inc. The transaction closed on December 13, 2002 and was effective on January 1, 2003. This sale is also consistent with our current strategy to focus our marketing activities on our North American physical assets. The sale of our international liquids business benefits liquidity by releasing significant amounts of previously posted collateral and removing lease obligations and parent guarantees related to shipping activities in the first quarter of 2003. We are in the process of finalizing a complete release of the ship lease, including the parent guarantee.
On an aggregate basis, this segment’s marketing, wholesale and global operations sold approximately 499,000 barrels per day of NGLs to approximately 740 different customers in 2002. In 2002 and 2001, approximately 28% and 23%, respectively, of our NGL sales were made to ChevronTexaco or one of its affiliates pursuant to the refinery agreements discussed above and pursuant to an agreement we have with Chevron Phillips Chemical Company. In the latter agreement, we supply most of Chevron Phillips Chemical’s NGL feedstock needs in the Mont Belvieu area and collect a cents-per-barrell fee for storage and product delivery.
Customer Risk Management
Our customer risk management, or CRM, segment consists of third-party marketing, trading and risk management activities unrelated to our generating assets. This segment provides these services to wholesale energy customers in North America, the United Kingdom and Continental Europe. In October 2002, we announced our exit from the CRM business, which has historically focused on the following activities:
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Purchases and sales of natural gas and power;
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Procurement of natural gas transportation services for our customers through pipelines owned by third parties;
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Storage of natural gas inventories in leased facilities for the purpose of offering peak delivery services to our customers;
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Management of power tolling arrangements in which we pay a fee for access to power generated by facilities that are owned and operated by third parties; and
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Execution of third-party, derivative financial instruments to manage the risks associated with commodity price fluctuations on behalf of our customers.
Since announcing our exit from the CRM business, we have made substantial progress in winding down our marketing and trading portfolio, particularly in the United Kingdom. Following is a list of actions we have taken related to this exit:
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In September and November 2002, we sold the subsidiaries that owned our U.K. natural gas storage business;
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In November 2002, we sold a portion of our Canadian natural gas marketing business;
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In December 2002, we terminated a previously existing long-term power tolling arrangement; and
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In January 2003, we announced the sale of our Canadian retail electricity marketing business.
Also in January 2003, we announced an agreement with ChevronTexaco to end the existing natural gas purchase and sale contracts related to ChevronTexaco’s North American production and consumption, effective February 1, 2003. Our CRM segment had purchased substantially all of ChevronTexaco’s lower-48 U.S. natural gas and supplied the natural gas requirements of ChevronTexaco’s corporate facilities through agreements that were to run until August 2006. We paid ChevronTexaco approximately $13 million in connection with ending the contracts, resolving balancing and other commercial matters and the transfer to ChevronTexaco of some related third-party contracts.
We have also taken various actions in the process of winding down our trading positions in this business. For example, we have sold a substantial portion of our natural gas in storage. In an effort to reduce the size of our marketing and trading portfolio, we have negotiated terminations of various marketing and trading agreements, or allowed them to expire, and generally have not entered into new transactions of this type. In the United Kingdom, we have terminated or sold all of our marketing and trading contracts in the region and have closed our U.K. office. The success of the efforts that we have taken to date is reflected in, among other things, a significant reduction in our collateral requirements associated with this business. Since September 30, 2002, we have reduced our collateral obligations in this business by approximately $585 million.
A significant component of our CRM segment is the eight power tolling arrangements to which we are a party. Pursuant to these eight agreements, we are obligated to make aggregate payments of approximately $3.8 billion to our counterparties in exchange for access to power generated by their facilities. Given our decision to exit from third-party risk management aspects of the marketing and trading business, we no longer consider this access to power as key to our business strategy. We are actively pursuing opportunities to assign or renegotiate the terms of our contractual obligations related to some of these agreements.
The following table contains a listing of our power tolling arrangements, including the name and location of each related project, the plant heat rate, the plant capacity and the term over which these payments are due:
Tolling Agreements
(1)
Project in development; contract begins in June 2005.
(2)
Includes a five-year extension option pursuant to which either party can elect to continue the arrangement depending on the market price for power at the expiration of the initial contract term.
Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations-Wholesale Energy Network” beginning on page 53 for further discussion of the potential impact of these power tolling agreements on our future results.
Corporate and Other
Our Other results include corporate governance roles and functions, which are managed on a consolidated basis, and specialized support functions such as finance, accounting, risk control, tax, corporate legal, corporate human resources, administration and technology. Corporate general and administrative expenses, income taxes and corporate interest expenses, which we previously allocated among our operating divisions, will be included in our other reported results, as well as corporate-related other income and expense items. Interest expense associated with borrowings incurred by our operating divisions, such as power generation facility financings, will continue to be reflected in the appropriate business segment’s results.
COMPETITION
Power Generation. Demand for power may be met by generation capacity based on several competing technologies, such as gas-fired, coal-fired or nuclear generation and 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 business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities and other energy service companies in the development and operation of energy-producing projects. We believe that our ability to compete effectively in this business 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. We believe our primary competitors in this business consist of approximately 15 companies.
Natural Gas Liquids. Our NGL businesses face significant and varied competitors, including major integrated oil companies, major pipeline companies and their marketing affiliates and national and local gas gatherers, processors, fractionators, brokers, marketers and distributors of varying sizes and experience. The principal areas of competition include obtaining gas supplies for gathering and processing operations, obtaining supplies of raw product for fractionation, purchase and marketing of NGLs, residue gas, condensate and sulfur, and transportation and storage of natural gas and NGLs. Competition typically is based on location and operating efficiency of facilities, reliability of services, delivery capabilities and price. We believe our primary competitors in this business consist of approximately 19 companies.
REGULATION
We are subject to regulation by various federal, state, local and foreign agencies, including the regulations described below.
Power Generation Regulation. Our power generation assets include projects that are Exempt Wholesale Generators, or EWGs, qualifying facilities, or QFs, or foreign utility companies, or FUCOs. One form of EWG is a merchant plant, which operates independently from designated power purchasers and, as a result, will generate and sell power to markets when electricity sales prices exceed the cost of production. A QF typically sells the power it generates to a single power purchaser.
The FPA grants the FERC exclusive ratemaking jurisdiction over wholesale sales of electricity in interstate commerce. Our power generation operations also are subject to regulation by the FERC under PURPA with respect to rates, the procurement and provision of certain services and operating standards. Although facilities deemed QFs under PURPA are exempt from ratemaking and other provisions of the FPA and the Public Utilities Holding Company Act of 1935, or PUHCA, non-QF independent power projects that are not otherwise exempt and certain power marketing activities are subject to the FPA and the FERC’s ratemaking jurisdiction, as well as PUHCA, and the Energy Policy Act of 1992. All of our current QF projects are qualifying facilities and, as such, under PURPA are exempt from the ratemaking and other provisions of the FPA. Our EWGs, which are not QFs, have been granted market-based rate authority and comply with the FPA requirements governing approval of wholesale rates and subsequent transfers of ownership interests in such projects.
In certain markets where we own power generation facilities, specifically California and New York, the FERC has from time to time approved and subsequently extended temporary price caps on wholesale power sales, or other market mitigation measures. Due to concerns over potential short supply and high prices in the summer of 2001, the NYISO, the FERC-approved operator of electric transmission facilities and centralized electric markets in New York, filed an Automated Mitigation Procedure proposal with the FERC. The proposal caps bid prices based on the cost characteristics of power generating facilities in New York, such as our Central Hudson facilities. In an order issued on June 28, 2001, the FERC accepted the proposal for the summer of 2001. In a subsequent order issued on November 27, 2001, the FERC extended the proposal through April 30, 2002. In an order issued in May 2002, the FERC modified and extended the proposal indefinitely, until the NYISO implements the FERC’s standard market design rules.
Price volatility and other market dislocations in the California market have precipitated a number of FERC actions related to the California market, and the Western market generally, in addition to price caps and market mitigation measures. These include an investigation of gas pipeline marketing affiliate abuse in the region, focused on whether, and to what extent, price refunds are owed by Dynegy and wholesale electricity suppliers serving California, and complaints requesting the FERC to reform or void various long-term power sales contracts. As a prelude to possible initiation of a new complaint proceeding, in the Spring of 2002, the FERC began investigating whether any entity has manipulated prices for electricity or natural gas in the West, since January 1, 2000, possibly resulting in unjust and unreasonable prices under long-term power sales contracts entered into since that time. On March 26, 2003, the FERC staff issued its Final Report on Price Manipulation in Western Markets, addressing a number of issues. The FERC staff also recommended that the FERC issue orders requiring that Dynegy and 36 other market participants be required to “show cause” why their activities did not violate the Cal ISO and Cal PX tariffs. Additional matters regarding our California operations are discussed in Item 8, Financial Statements and Supplementary Data, Note 14-Commitments and Contingencies beginning on page.
On November 20, 2001, the FERC issued an order that would subject the prospective sales of all entities with market-based rate tariffs to “refunds or other remedies” in the event the seller engages in “anti-competitive behavior or the exercise of market power.” The FERC has postponed the effectiveness of this refund condition pending its consideration of comments submitted by interested parties. Dynegy and other similarly-situated
generators and power marketers have submitted comments in opposition to the proposed refund condition. It is uncertain how the FERC will act with respect to this matter. If the FERC were to establish the broad refund condition proposed, it would increase the risk inherent in electric marketing activities for all wholesale sellers of electricity, including us. Establishment of the proposed refund condition, together with a finding that we engaged in any of the specified activities, also could require us to refund some of the electricity payments we have collected.
Electricity Marketing Regulation. Our electricity marketing operations are regulated by the Federal Power Act and the FERC with respect to rates, terms and conditions of services and various reporting requirements. Current FERC policies permit trading and marketing entities to market electricity at market-based rates. While the FERC has affirmed its desire to move toward competitive markets with market-based pricing, it is currently reviewing the specifics of implementing this policy. For further discussion, please see “-Power Generation Regulation” beginning on page 19 above.
In December 1999, the FERC issued Order No. 2000, which addressed a number of issues relating to the regional transmission of electricity. In particular, Order No. 2000 provided for regional transmission organizations, or RTOs, to control the transmission facilities within a particular region. After a period of progress toward voluntary creation of RTOs as envisioned by the FERC, activity has slowed due to controversy and uncertainty concerning required standards and structures for such entities. Recently, the FERC proposed new rules designed to result in the adoption of generally standardized market terms and conditions governing interstate transmission and RTO operation of markets. The FERC also proposed generic standards and procedures for the interconnection of generation to the transmission grid. These proposed rules are controversial, particularly with some legislators and state regulatory bodies, and have generated significant opposition. The FERC also has directed electric industry participants to establish a single organization to assist with the development of business practices and protocols that will be needed to implement such standardized terms and conditions. It is uncertain what rules the FERC may adopt as the result of these proceedings. The impact of these RTOs on our electricity marketing operations cannot be predicted.
Recently, the FERC announced a new policy concerning its approvals of utilities’ securities issuances, including debt, and to assume liabilities and obligations of others. Under the new policy, such approvals of such requirements will be conditioned upon a requirement that any secured debt incurred follow the disposition of assets used to secure it, and if secured by public utility assets, must only be incurred for public utility purposes and if unsecured, must proportionately follow any assets financed with its proceeds if those assets are transferred.
Natural Gas Processing. Our natural gas processing operations could become subject to FERC regulation. The FERC has traditionally maintained that a processing plant used primarily for removal of NGLs for economic purposes is not a facility for transportation or sale for resale of natural gas in interstate commerce and, therefore, is not subject to jurisdiction under the NGA. However, the FERC considers a processing plant used primarily for purposes related to transportation safety and efficiency to be subject to such regulation. We believe our gas processing plants are primarily involved in removing NGLs for economic purposes and, therefore, are exempt from FERC jurisdiction. Nevertheless, the FERC has made no specific finding as to our gas processing plants. As such, no assurance can be given that all of our processing operations will remain exempt from FERC regulation.
Natural Gas Gathering. The NGA exempts gas gathering facilities from the jurisdiction of the FERC, while interstate transmission facilities remain subject to FERC jurisdiction, as described above. We believe our gathering facilities and operations meet the current tests used by the FERC to determine nonjurisdictional gathering facility status, although the FERC’s articulation and application of such tests have varied over time. Nevertheless, the FERC has made no specific findings as to the exempt status of any of our facilities. No assurance can be given that all of our gas gathering facilities will remain classified as such and, therefore, remain exempt from FERC regulation. Some states regulate gathering facilities to varying degrees; generally, rates are not regulated.
Liquified Natural Gas (LNG) Terminals. LNG terminals operating in interstate commerce are subject to FERC jurisdiction and regulation of rates, terms and conditions of service. The FERC recently announced a new policy applicable to new LNG terminals, such as our proposed facility, which will apply less stringent regulation to such facilities as compared to that described above concerning interstate natural gas transportation and storage. Under this new policy, such LNG facilities need not operate on an open-access basis, and may offer rates, terms and conditions of service mutually agreed to with shippers, rather than as established by FERC. We recently received preliminary FERC approval to construct such a facility in Louisiana. We have entered into an agreement to sell this facility to Sempra LNG Corp., a subsidiary of San Diego-based Sempra Energy. The transaction is subject to the satisfaction of certain conditions and is expected to close in the early part of the second quarter.
Natural Gas Regulation. The transportation (including storage) and sale for resale of natural gas in interstate commerce is subject to regulation by the FERC under the Natural Gas Act of 1938, as amended, and, to a lesser extent, the Natural Gas Policy Act of 1978, as amended. The rates charged by interstate pipelines for interstate transportation and storage services, and the terms and conditions for provision of such services, are regulated by the FERC, which generally also must approve any changes to these rates or terms and conditions prior to their implementation. The FERC also has jurisdiction over, among other things, the construction and operation of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion, acquisition, disposition, or abandonment of such facilities; maintenance of accounts and records; depreciation and amortization policies; and transactions with and conduct of interstate pipelines relating to affiliates. Our Venice Gathering System is a regulated interstate pipeline.
Commencing in 1992, the FERC issued Order No. 636 and subsequent orders, which require interstate pipelines to provide transportation separate, or “unbundled,” from the pipelines’ sales of gas. These orders also require pipelines to provide open-access transportation on a basis that is equal for all shippers. The FERC intends for these orders to foster increased competition within all phases of the natural gas industry. Prior to our acquisition of the Venice Gathering System, these orders did not directly regulate any of our activities; however, like other interstate pipelines, Venice Gathering System must comply with FERC’s open-access transportation regulations. The implementation of these orders has not had a material adverse effect on our results of operations. The courts have largely affirmed the significant features of these and numerous related orders pertaining to the individual pipelines, although some appeals remain pending and the FERC continues to review and modify its open-access regulations.
In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, these orders revised the FERC pricing policy by waiving price ceilings for short-term released interstate pipeline transportation capacity for a two-year period, and effected changes in the FERC regulations relating to interstate transportation scheduling procedures, capacity segmentation, pipeline penalties, rights of first refusal and information reporting. Most major aspects of these orders were upheld on judicial review, though some issues were remanded to the FERC, have been considered on remand and are pending rehearing at the FERC. It is uncertain whether and to what extent the FERC’s market reforms will survive rehearing and further judicial review and, if so, whether the FERC’s actions will achieve the goal of further increasing competition in natural gas markets.
The FERC has proposed to expand its existing rules governing the conduct of interstate pipelines and their marketing affiliates to include all energy affiliates. If adopted, the proposed rule would, among other things, preclude the exchange of transportation-related information among an interstate pipeline and any of its energy affiliates. The FERC has stated that one purpose of the proposal is to allow pipeline affiliates and non-affiliates to compete in energy markets on an even basis. It is uncertain whether or when the FERC may adopt the proposed rule, or the extent to which it may affect the cost or other aspects of our operations; however, we do not anticipate that our regulated transmission provider and its energy affiliates will be impacted any differently than other similar industry participants.
Pursuant to the NGPA and the Wellhead Decontrol Act of 1989, most sales of natural gas are no longer subject to price controls. However, the FERC retains jurisdiction over certain sales made by interstate pipelines
or their affiliates. Currently, the FERC has authorized such sales to be made at unregulated prices, terms and conditions. While sales of natural gas can currently be made at market prices, and upon unregulated terms and conditions, there is no assurance that such regulatory treatment will continue indefinitely in the future. Congress or, as to sales remaining subject to its jurisdiction, the FERC, could re-enact price controls or other regulation in the future.
State Regulatory Reforms. Our domestic natural gas and power marketing, and power generation businesses are subject to various regulations from the states in which we operate. Proposed reforms to these regulations, and in some cases, repeal of measures implementing retail competition, are proceeding in several states, including California, the results of which could affect our operations.
Legislation. In the last legislative session, the United States Congress considered, but ultimately did not pass, a number of bills that could have impacted regulations applied to us and our subsidiaries, including bills that would repeal the PUHCA and portions of the PURPA and that would affect the FERC’s regulatory authority over energy marketing, generation and trading. Recent market events including the California electricity crisis in late 2000 and the alleged manipulation of electricity prices by Dynegy and other wholesale electricity merchants have prompted questions about the wisdom of the PUHCA repeal and whether more stringent regulation may be needed. We cannot predict with certainty what energy legislation may be considered in the current legislative session, whether any such legislation will become law or what effect any such new legislation might have.
ENVIRONMENTAL AND OTHER MATTERS
General. Our operations are subject to extensive federal, state and local statutes, rules and regulations governing the discharge of materials into the environment or otherwise relating to environmental, health and safety protection. In addition, development of projects in international markets creates exposure to and obligations under the national, provincial and local laws of each host country, including environmental standards and requirements imposed by these governments. Environmental laws and regulations, including environmental regulators’ interpretations of these laws and regulations, are complex, change frequently and have tended to become more stringent over time. Many environmental laws require permits from governmental authorities before construction on a project may be commenced 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 either unprofitable or otherwise unattractive. Even where permits are not required, compliance with environmental laws and regulations can require significant capital and operating expenditures, and we may be required to incur costs to remediate contamination from past releases of wastes into the environment. Failure to comply with these statutes, rules and regulations may result in the assessment of administrative, civil and even criminal penalties. Furthermore, the failure to obtain or renew an environmental permit could prevent operation of one or more of our facilities.
In general, the construction and operation of our facilities are subject to federal, state and local environmental laws and regulations governing the siting of energy facilities, the discharge of pollutants and other materials into the environment, the protection of wetlands, endangered species, and other natural resources, the control and abatement of noise and other similar requirements. A variety of permits are typically required before construction of a project commences, and additional permits are typically required for facility operation.
Environmental Expenditures. Our aggregate expenditures for compliance with laws and regulations related to the protection of the environment were approximately $82 million in 2002, compared to approximately $81 million in 2001 and approximately $121 million in 2000. We estimate that total environmental expenditures (both capital and operating) in 2003 will be approximately $52 million. A majority of our environmental expenditures relate to the federal Clean Air Act and comparable state laws and regulations. Management does not expect capital spending on environmental matters to increase materially over the near term; however, changes in
environmental regulations or the outcome of litigation could result in additional requirements that could necessitate increased spending. Please read “-The Clean Air Act” below for a discussion of the litigation brought by the Environmental Projection Agency against two Dynegy affiliates relating to activities at our Baldwin generating station in Illinois.
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 and annual compliance and reporting obligations. Although the impact of air quality regulations cannot be predicted with certainty, these regulations are expected to become increasingly stringent, particularly for electric power generating facilities. Clean Air Act requirements include the following:
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The Clean Air Act Amendments of 1990 required a two-phase reduction by electric utilities in emissions of sulfur dioxide and nitrogen oxide by 2000 as part of an overall plan to reduce acid rain in the eastern United States. Installation of control equipment and changes in fuel mix and operating practices have been completed at our facilities as necessary to comply with the emission reduction requirements of the acid rain provision of the Clean Air Act Amendment of 1990.
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In October 1998, the EPA issued a final rule on regional ozone control that required 22 eastern states and the District of Columbia to revise their State Implementation Plans to significantly reduce emissions of nitrogen oxide. The current compliance deadline for implementation of these emission reductions is May 31, 2004. In January 2000, the EPA finalized another ozone-related rule under Section 126 of the Clean Air Act that has similar emission control requirements. The required capital expenditures and installation of the necessary emission control equipment to meet these requirements has been largely completed; consequently, we expect the power generation system will meet the specified compliance deadlines for implementation. Portions of our NGL business are also subject to these rules. We have plans in place to satisfy these requirements and expect to incur capital expenditures of approximately $6.5 million pursuant to such plans.
Multi-Pollutant Air Emission Initiatives. Various multi-pollutant proposals have been introduced at the federal and state level. An example is the “Clear Skies Initiative” announced by the President in 2002. The “Clear Skies” proposal is aimed at long-term reductions of multiple pollutants produced from fossil fuel-fired power plants. Reductions averaging 70% are targeted for sulfur dioxide, NOx and mercury. In addition, the President has proposed a voluntary program for reducing greenhouse gas emissions such as carbon dioxide. The implementation of this initiative, if approved by Congress, would be via a market-based program, modeled after the Acid Rain Program, beginning in 2008 and phased full compliance by 2018. Fossil fuel-fired power plants in the United States would be affected by the adoption of this program, or other multi-pollutant legislation currently proposed by Congress addressing similar issues. Such programs would require compliance to be achieved by the installation of pollution controls, the purchase of emission allowances or curtailment of operations.
MACT. The EPA has announced its determination to regulate hazardous air pollutants including mercury, from coal-fired and oil-fired steam electric generating units under Section 112 of the Clean Air Act. The EPA plans to develop maximum achievable control technology standards for these types of units. The rulemaking for coal and oil-fired steam electric generating units is expected to be completed by December 2004. Compliance with the rules will likely be required within three or four years thereafter.
The MACT standards that will be applicable to the units cannot be predicted at this time and could have an adverse impact on our operations. As well, we cannot predict the additional impact that the MACT standard would have over and above any proposed multi-pollutant legislation. Although the impact of possible future environmental requirements cannot be predicted with any degree of certainty, any expenditures that are ultimately required are not anticipated to have a more significant effect on our operations or financial condition than on any similarly situated company that generates electricity through the burning of fossil fuels.
Baldwin Station Litigation. IP and DMG, referred to in this section as the Defendants, are currently the subject of a Notice of Violation, or NOV, from the EPA and a complaint filed by the EPA and the Department of
Justice alleging violations of the Clean Air Act and the regulations promulgated under the Clean Air Act. Similar notices and complaints have been filed against a number of other utilities. Both the NOV and the complaint allege that certain equipment repairs, replacements and maintenance activities at the Defendants’ three Baldwin Station generating units in Illinois constituted “major modifications” under the Prevention of Significant Deterioration (PSD) and/or the New Source Performance Standards (NSPS) regulations. When activities that meet the definition of “major modifications” occur and are not otherwise exempt, the Clean Air Act and related regulations generally require that generating facilities meet more stringent emissions standards, which may entail the installation of potentially costly pollution control equipment. The Defendants filed an answer denying all claims and asserting various specific defenses and a trial date of June 3, 2003 has been set.
We believe that the Defendants have meritorious defenses to the EPA allegations and will vigorously defend against these claims. On February 18, 2003, the Court granted the Defendants’ motion for partial summary judgment based on the five-year statute of limitations. As a result of the Court’s ruling, the EPA will not be able to seek any monetary civil penalties for claims related to construction without a permit under the PSD regulations. The Order also precludes monetary civil penalties for a portion of the claims under the NSPS regulations. The Company has recorded a reserve for potential penalties that could be imposed if the EPA were to prosecute its claims successfully. Please read Item 8, Financial Statements and Supplementary Data, Note 14-Commitments and Contingencies beginning on page for further discussion of this lawsuit.
On December 31, 2002, the EPA proposed several reforms to its regulations governing new source review. These reforms, if made, would clarify the routine maintenance, repair and replacement exclusion, provide more certainty in evaluating permit requirements and increase operational flexibility for affected facilities.
Water Issues. Our wastewater discharges are permitted under the Clean Water Act and analogous state laws. These permits are subject to review every five years. The state-issued water discharge permits associated with the DNE facilities expired in 1992. However, under New York State law, each permit remains in effect and allows for continued operation under the terms of the original permits, given that timely applications requesting renewal were filed as required. Although the renewal process has been underway from some time, joint legal action has been taken recently by several interested third parties. The petitioners in this matter are requesting that the permit renewal process be completed in an expeditious manner. In November 2001, the EPA promulgated rules that impose additional technology-based requirements on new cooling water intake structures. Draft rules for existing intake structures have also been issued. It is not known at this time what requirements the final rules for existing intake structures will impose or whether our existing intake structures will require modification as a result of such requirements.
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 EPA to evaluate water quality criteria for parameters associated with the by-products of fossil fuel combustion. These parameters include arsenic, mercury and selenium. Significant changes in these criteria could impact station discharge limits and could require our facilities to install additional water treatment equipment. The final impact on us as a result of these initiatives is unknown at this time; however, it is reasonable to assume that we would incur additional compliance costs as a result of the increased regulation of water quality.
Remedial Laws. We are also subject to environmental remediation requirements, including provisions of the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, and the corrective action provisions of the federal Resource Conservation and Recovery Act, or RCRA, and similar state laws. CERCLA imposes liability, regardless of fault or the legality of the original conduct, 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 the disposal, of the hazardous substance found at a facility. CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to public health or the environment and to seek recovery for the costs of cleaning up the hazardous substances that have been released and for damages to natural resources from such responsible party.
Further, it is not uncommon for neighboring landowners and other affected parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. CERCLA or RCRA could impose remedial obligations at a variety of our facilities.
Additionally, the EPA may develop new regulations that impose additional requirements on facilities that store or dispose of fossil fuel combustion materials, including coal ash. If so, power generators like us 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 insulation, other asbestos containing materials and lead-based paint. 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.
Pipeline Safety. In addition to environmental regulatory issues, the design, construction, operation and maintenance of some of our pipeline facilities is subject to the safety regulations established by the Secretary of the U.S. Department of Transportation pursuant to the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, or by state regulations meeting the requirements of the NGPSA and the HLPSA, or to similar statutes, rules and regulations in Canada or other jurisdictions. In December 2000, the DOT adopted new regulations requiring operators of interstate pipelines to develop and follow an integrity management program that provides for continual assessment of the integrity of all pipeline segments that could affect so-called “high consequence” environmental impact areas, through periodic internal inspection, pressure testing or other equally effective assessment means. An operator’s program to comply with the new rule must also provide for periodically evaluating the pipeline segments through comprehensive information analysis, remediating potential problems found through the required assessment and evaluation, and assuring additional protection for the high consequence segments through preventative and mitigative measures. The requirements of this new DOT rule will likely increase the costs of pipeline operations.
In the wake of the September 11, 2001 terrorist attacks on the United States, the DOT has developed a security guidance document and has issued a security circular that defines critical pipeline facilities and appropriate countermeasures for protecting them, and explains how the DOT plans to verify that operators have taken appropriate action to implement satisfactory security procedures and plans. Using the guidelines provided by the DOT, we have specifically identified certain of our facilities as DOT “critical facilities” and therefore potential terrorist targets. In compliance with the DOT guidance, we are performing vulnerability analyses on such facilities. Additional security measures and procedures may be adopted or implemented upon completion of these analyses, and any such measures or procedures have the potential for increasing our costs of doing business. Regardless of the steps taken to increase security, however, we cannot be assured that our facilities will not become the subject of a terrorist attack. Please read “-Operational Risks and Insurance” beginning on page 26 for further discussion.
Health and Safety. Our operations are subject to the requirements of the Federal Occupational Safety and Health Act (“OSHA”) and other comparable federal, state and provincial statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Superfund Amendments and Reauthorization Act and similar state statutes require that information be organized and maintained about hazardous materials used or produced in our operations. Some of this information must be provided to employees, state and local government authorities and citizens. We believe we are currently in substantial compliance, and expect to continue to comply in all material respects, with these rules and regulations.
Subject to resolution of the complaints filed by the EPA and the DOJ against IP and DMG, which are described in Item 8, Financial Statements and Supplementary Data, Note 14-Commitments and Contingencies
beginning on page, management believes that it is in substantial compliance with, and is expected to continue to comply in all material respects with, applicable environmental statutes, regulations, orders and rules. Further, to management’s knowledge, other than the previously referenced complaints, there are no existing, pending or threatened actions, suits, investigations, inquiries, proceedings or clean-up obligations by any governmental authority or third party relating to any violations of any environmental laws with respect to our assets or pertaining to any indemnification obligations with respect to properties previously owned or operated by us, which could reasonably be expected to have a material adverse effect on our operations and financial condition.
OPERATIONAL RISKS AND INSURANCE
We are subject to all risks inherent in the various businesses in which we operate. These risks include, but are not limited to, explosions, fires, terrorist attacks, product spillage, weather, nature and the public, 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 adequate for such risks. Such insurance is subject to deductibles that we consider reasonable and not excessive given the current insurance market environment. The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. In addition, the terrorist attacks on September 11, 2001 and the changes in the insurance markets attributable to those attacks have made some types of insurance more difficult or costly to obtain. We may be unable to secure the levels and types of insurance we would otherwise have secured prior to September 11, 2001. No assurance can be given that we will be able to maintain adequate levels of insurance in the future at rates we consider reasonable.
In our CRM segment, we also face market, price, credit and other risks relative to our orderly exit from third-party risk-management aspects of the gas and power marketing and trading business. Please read Item 7A, Quantative and Qualitative Disclosures About Market Risk, beginning on page 67 for further discussion of these risks.
In addition to these commercial risks, we also face the risk of reputational damage 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 the 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 reputational damage in the industries in which we compete and to financial loss. Please read Item 14, Controls and Procedures beginning on page 72 for further discussion of our internal control systems and the efforts that we are undertaking with respect to such systems.
SIGNIFICANT CUSTOMER
For the years ended December 31, 2002, 2001 and 2000, we derived approximately 18%, 12% and 16% of our consolidated revenues from transactions with ChevronTexaco. For the same three years, purchases from ChevronTexaco consisted of approximately 48%, 52% and 49% of our consolidated costs of sales. No other customer accounted for more than 10% of our consolidated revenues or consolidated cost of sales during 2002, 2001 and 2000.
Item 2.
Item 2. Properties
We have included descriptions of the location and general character of our principal physical operating properties by segment in Item 1, Business beginning on page 2. Those descriptions are incorporated herein by this reference.
Our principal executive office located in Houston, Texas is held under a lease that expires in December 2007. We also lease offices in the states of California, Florida, Georgia, Massachusetts, New Jersey, Illinois, Texas and Virginia and in London.
Item 3.
Item 3. Legal Proceedings
For a description of our material legal proceedings, please read Item 8, Financial Statements and Supplementary Data, Note 14-Commitments and Contingencies, beginning on page, which is incorporated herein by reference.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
Omitted pursuant to General Instruction (I)(2)(c) of Form 10-K.
PART II
Item
5.
Item
5. Market for Registrant’s Common Equity and Related Stockholder Matters
All of our outstanding equity securities are held by our parent, Dynegy Inc. There is no established trading market for such securities and they are not traded on any exchange.
Securities Authorized for Issuance Under Equity Compensation Plans
We have no equity compensation plans pursuant to which our employees are granted stock options or other equity compensation. Our employees do, however, receive stock options pursuant to plans maintained by our parent company, Dynegy Inc. Please read Dynegy Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002 for a discussion of these plans.
Item 6.
Item 6. Selected Financial Data
The selected financial information presented below was derived from, and is qualified by reference to, our Consolidated Financial Statements, including the notes thereto, contained elsewhere herein. The selected financial information should be read in conjunction with the Consolidated Financial Statements and related notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The historical information contained in the table below has been revised to reflect the restatement items otherwise contained in Amendment No. 1 to our 2001 Form 10-K. Please read the Explanatory Note to the accompanying financial statements beginning on page for further discussion of these restatements.
Dynegy’s Selected Financial Data
(1)
The following acquisitions were accounted for in accordance with the purchase method of accounting and the results of operations attributable to the acquired businesses are included in our financial statements and operating statistics beginning on the acquisitions’ effective date for accounting purposes:
•
Northern Natural - February 1, 2002; and
•
BGSL - December 1, 2001.
(2)
The Northern Natural and BGSL acquisitions were each accounted for under the purchase method of accounting. Accordingly, the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated fair values as of the effective dates of each transaction. See note (1) above for respective effective dates.
(3)
Discontinued operations includes the results of operations from the following businesses:
•
Northern Natural (sold August 2002);
•
UK Storage-Hornsea facility (sold October 2002) and Rough facility (sold November 2002); and
•
Global Liquids (sold December 2002).
(4)
As described elsewhere in this report, the financial statements contained herein include the effects of various restatement items. Approximately $55 million of the restatement items relate to periods prior to 1999, the most significant of which is related to the re-allocation of an $80 million after-tax charge (previously recognized in the second quarter 2002) associated with our natural gas marketing business. For purposes of this Selected Financial Data table, we have included the entire $55 million in the balance sheet, statement of operations, cash flow and other financial data for the year ended December 31, 1998. Management does not believe that the failure to allocate this $55 million to periods prior to 1999 is material to the presentation of our financial results or known material trends or contingencies in our business.
(5)
The 2001 and 2000 amounts include amounts relating to the Black Thunder transaction discussed in Item 8, Financial Statements and Supplementary Data, Note 10-Debt beginning on page.
(6)
As further discussed in Item 8, Financial Statements and Supplementary Data, Note 2-Accounting Policies beginning on page, revenue amounts have been restated to reflect the adoption of the net presentation provisions in EITF 02-03.
(7)
The consolidated financial statements for the year ended December 31, 1998 were audited by other independent accountants who have ceased operations.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
We are a holding company and conduct substantially all of our business operations through our subsidiaries. We own operating divisions engaged in power generation and natural gas liquids. Through these operating divisions, we serve customers by delivering value-added solutions to meet their energy needs.
We are in the process of restructuring our company in response to events that have negatively impacted the merchant energy industry, and our company in particular, over the past year. This restructuring includes significant changes in our operations, primarily our exit from third-party risk management aspects of the marketing and trading business. Our restructuring also includes significant financial transactions that have stabilized our liquidity position and begun the process of decreasing our substantial financial leverage. Significant accomplishments include the following:
•
The sale of Northern Natural Gas Company;
•
The sale of our U.K. natural gas storage business;
•
The sale of our global liquids business;
•
Major progress towards our exit from the third-party marketing and trading or customer risk management business, including the completion of our exit from European marketing and trading and the transition of ChevronTexaco’s natural gas marketing business back to ChevronTexaco, and the reduction of associated collateral requirements;
•
The extension of the maturity of our two primary bank credit facilities until February 2005; and
•
Considerable workforce reductions, which we expect will provide substantial general and administrative cost savings.
In our new, simplified operating structure, we intend to focus on being a low-cost producer of physical products and provider of services in each of our two main operating divisions. Our customer risk management business, including obligations relating to the eight long-term power tolling arrangements to which we remain a party, will continue to affect our future results of operations until the related obligations have been satisfied or restructured. Our results will also be significantly affected by higher borrowing costs.
LIQUIDITY AND CAPITAL RESOURCES
Overview
We faced significant challenges relating to our liquidity position in 2002. These challenges were caused by several factors affecting the merchant energy industry, and particularly our company, including the following:
•
The application of more stringent credit standards to Dynegy and other energy merchants;
•
Weak commodity prices, particularly for power;
•
A reduction in liquidity and amount of open trade credit available to counterparties in the marketing and trading business;
•
The various lawsuits and governmental investigations involving our company, including matters relating to Project Alpha, our past trading practices and our activities in the California power market;
•
Downgrades in our credit ratings to well below investment grade, resulting in substantial requirements to provide counterparties with collateral support in order to transact new business or avoid the termination of existing transactions; and
•
The restatement of our 1999-2001 financial results, the related three-year re-audit and the unavailability of 2001 audited financial statements, all of which limited our ability to access the capital markets.
We also were negatively impacted by our limited ability to generate the expected return on the significant capital we had previously invested in our new merchant generation facilities, because of a weak pricing environment.
In relation to these events, we posted significantly higher amounts of collateral in the forms of cash and letters of credit than we had in the past. For example, at September 30, 2002, we had posted approximately $1.2 billion of letters of credit and cash collateral in support of our marketing and trading and asset-based businesses. This compares to the approximately $448 million in collateral that we had posted at December 31, 2001.
Since September 30, 2002, we have made marked progress in our exit from third-party risk management aspects of the marketing and trading business. The actions taken in this regard, particularly the transfer of the ChevronTexaco natural gas marketing business back to ChevronTexaco and the completion of our exit from U.K. marketing and trading, resulted in the return of approximately $250 million of collateral and the elimination of these collateral requirements going forward. However, our ongoing asset businesses will continue to manage commodity price risk and optimize commercial positions associated with their respective operations through, among other things, fuel procurement optimization and the marketing of power and NGLs. We expect to continue to post collateral to support these operations, the amount and term of which will be impacted by changes in commodity prices. At April 2, 2003, we had an aggregate of approximately $1.0 billion of letters of credit and cash collateral outstanding. While the completion of our exit from third-party risk management aspects of the marketing and trading business will result in a reduction in the collateral requirements associated with that business, we expect an increase in the collateral requirements relating to fuel procurement for our asset-based business given our non-investment grade credit ratings and higher commodity prices.
We have also successfully completed a restructuring of our revolving credit facilities that were to expire in April and May of this year. By extending the maturity date of these obligations, which totaled approximately
$1.3 billion at April 2, 2003, together with the successful execution of our other liquidity initiatives, we believe that we have provided our company with sufficient capital resources to meet our current debt obligations and provide collateral support for our ongoing asset businesses and our continued exit from third-party marketing and trading through 2004. However, our success and future financial condition, including our ability to refinance our substantial debt maturities in 2005 and thereafter, will depend on our ability to successfully execute the remainder of our exit from third-party marketing and trading and to produce adequate operating cash flows from our continuing asset-based businesses to meet our debt and commercial obligations, including substantial increases in interest expense. Please read “Uncertainty of Forward-Looking Statements and Information” beginning on page 66 for additional factors that could impact our future operating results and financial condition.
Liquidity Sources
As described above, we faced severe strains on our liquidity during 2002. These strains were most severe in the middle of the year, prior to our completion of several initiatives, the proceeds of which have allowed us to stabilize our liquidity position. Important initiatives included the sale of our U.K. natural gas storage assets, the disposition of our global liquids business and the sale of Northern Natural. The net proceeds from these initiatives and the reduction in related collateral requirements have enabled us to stabilize our liquidity position and to satisfy the collateral requirements of our suppliers, customers and trading counterparties.
These liquidity initiatives originated with Dynegy Inc.’s $1.25 billion capital program, which they announced in December 2001. This program included a $300 million reduction to our original 2002 capital spending program. However, with increasing collateral demands and significant near-term maturities, we adopted a number of additional restructuring objectives during the latter half of 2002.
The following table lists the liquidity initiatives that we have successfully executed since June 2002 (amounts reflect gross proceeds prior to reduction for applicable fees).
Date
Initiative
June 2002
• $250 million interim financing secured by proceeds from the sale of our U.K. natural gas storage business
• Refinancing of West Coast Power debt, resulting in the release of $100 million in letters of credit previously posted by us on West Coast Power’s behalf
• Reduction in workforce (309 employees)
July 2002
• $200 million interim financing secured by interests in the Renaissance and Rolling Hills generating facilities
August 2002
• Sale of Northern Natural
September 2002
• Sale of Northern Natural senior notes for $96 million
• Sale of Hornsea (portion of U.K. natural gas storage business) for $189 million, the proceeds from which were used to partially repay the $250 million related interim financing
October 2002
• Commencement of exit from third-party marketing and trading business
• Implementation of organizational restructuring
• Reduction in workforce (780 employees)
November 2002
• Sale of Rough (then-remaining portion of U.K. natural gas storage business) for $500 million, with $61 million of the proceeds used to repay the remaining outstanding balance under the $250 million related interim financing
• Sale of portions of the Canadian marketing and trading business
December 2002
• Extension of $106 million of the original $200 million Renaissance and Rolling Hills interim financing
January 2003
• Disposition of global liquids business resulting in reduced collateral requirements and other commitments
• Termination of ChevronTexaco Gas Marketing Agreement
February 2003
• Agreement to sell Hackberry LNG Project for $20 million, with additional contingent payments based upon project development milestones and performance
March 2003
• Completion of exit from European marketing and trading business
• Sale of equity interest in SouthStar Energy Services LLC for $20 million
April 2003
• Restructuring of our primary credit facilities
Because of our non-investment grade status and our limited ability to access the capital markets, we have relied, and expect to continue to rely, on cash proceeds from these liquidity initiatives, together with cash from operations and borrowings under our revolving credit facilities, to satisfy our capital requirements. The following table summarizes our consolidated credit capacity and liquidity position at December 31, 2002 and April 2, 2003, respectively.
(1)
Consists principally of natural gas inventories that have largely been monetized in the first quarter 2003. The values presented are based on spot market prices as of December 31, 2002 and April 2, 2003, respectively.
(2)
Reflects an approximately $500 million increase in cash collateral, and a comparable reduction in letters of credit outstanding, since December 31, 2002. This temporary change resulted from our use of cash to collateralize our obligations, as opposed to letters of credit, late in the first quarter because the near-term nature of the maturity dates on our revolving credit facilities did not permit the issuance of letters of credit. In light of the restructuring of our revolving credit facilities, we expect to return to using letters of credit as opposed to cash to collateralize these obligations in the coming months. Also reflects $131 million of debt payments in the first quarter 2003, including a $94 million payment made in January 2003 on our $200 million Renaissance and Rolling Hills financing.
Liquidity Uses
At December 31, 2002, we had posted approximately $1.2 billion of letters of credit and cash collateral relating to our marketing and trading business and our asset-based business. This compares to approximately $448 million of letters of credit and cash collateral that we had posted at December 31, 2001. Although we experienced a substantial increase in our liquidity usage for collateral requirements during 2002, the success of our restructuring efforts to date has improved our liquidity position and enabled us to generally satisfy the collateral requirements of our customers and counterparties.
The following table includes significant liquidity uses with respect to debt repayments in 2002:
Bank Restructuring
On April 2, 2003, we entered into a $1.66 billion bank credit facility consisting of:
•
a $1.1 billion secured revolving credit facility (the “revolving facility”) and a $200 million secured term loan (“Term A facility”), each of which matures on February 15, 2005; and
•
a $360 million secured term loan (“Term B facility”) that matures on December 15, 2005.
The credit facility replaces, and preserves the commitment of each lender under, our $900 million and $400 million revolving credit facilities, which had maturity dates of April 28, 2003 and May 27, 2003, respectively, and Dynegy Inc.’s $360 million Polaris communications lease, which had a maturity date of December 15, 2005. The credit facility will provide funding for general corporate purposes. The revolving facility is also available for the issuance of letters of credit. Borrowings under the credit facility will bear interest, at our option, at (i) a base rate plus 3.75% per annum or (ii) LIBOR plus 4.75% per annum. A letter of credit fee will be payable on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 4.75% of the undrawn amount. An unused commitment fee of 0.50% will be payable on the unused portion of the revolving facility.
Subject to restrictions contained in the credit facility, amounts repaid under the revolving facility may be reborrowed. The full amounts of the borrowings under the Term A facility and the Term B facility were borrowed at the closing, and borrowings repaid under these facilities may not be reborrowed.
The credit facility contains mandatory prepayment events. The credit facility must, subject to specified exceptions, be repaid and commitments permanently reduced with:
•
100% of the net cash proceeds of all non-ordinary course asset sales;
•
50% of the net cash proceeds from the issuance of equity or subordinated debt;
•
100% of the net cash proceeds from the issuance of senior debt; and
•
50% of extraordinary receipts.
The credit facility provides for no amortization of principal amounts outstanding prior to the maturity dates except upon the occurrence of such a prepayment event.
Subject to specified exceptions, our obligations under the credit facility are guaranteed by Dynegy Inc. and substantially all of Dynegy Inc.’s direct and indirect subsidiaries, excluding (i) IP and DGC and their respective subsidiaries, (ii) most foreign subsidiaries, dormant subsidiaries and subsidiaries with de minimus value and (iii) subsidiaries that are unable to become guarantors due to existing contractual or legal restrictions.
Subject to specified exceptions and permitted liens, the lenders under the credit facility received a first priority lien in substantially all the assets of Dynegy Inc., us and certain of the subsidiary guarantors to the extent practicable and permitted by existing contractual arrangements, excluding IP and DGC and their respective subsidiaries. The lenders also received a first priority lien in the ownership interests in Dynegy Inc.’s direct and indirect subsidiaries, including us but excluding (i) IP and DGC and their respective subsidiaries, (ii) most foreign subsidiaries, dormant subsidiaries and subsidiaries with de minimus value and (iii) subsidiaries whose ownership interests may not be pledged due to existing contractual or legal restrictions. The lenders also received a second priority lien in all material assets of DMG, subject to the first priority lien granted to the lenders under the Black Thunder financing. Our obligations under the Project Alpha transaction and CoGen Lyondell and Riverside generating facility leases were ratably secured with the same assets pledged to the lenders under the credit facility as required by the terms of those facilities.
The credit facility contains affirmative covenants relating to, among other things, financial statements; compliance and other certificates; notices of specified events; payment of obligations; preservation of existence; maintenance of properties; maintenance of insurance; compliance with laws; maintenance of books and records; inspection rights; use of proceeds; guarantee obligations and security; compliance with environmental laws; preparation of environmental reports; further assurances; material contracts; distribution of cash proceeds and extraordinary receipts by subsidiaries; and mortgaged property. The credit facility contains negative covenants relating to, among other things, liens; investments; indebtedness; fundamental changes; dispositions; restricted payments; changes in business; transactions with affiliates and non-loan parties; burdensome agreements; use of proceeds; amendments to organizational documents; accounting changes; prepayments of indebtedness; material contracts; swap contracts and off-balance sheet arrangements; formation of subsidiaries; the CoGen Lyondell and Riverside facilities; and amendments to the Dynegy Inc. Series B preferred stock held by ChevronTexaco. The credit facility also contains financial and capital expenditure-related covenants, which are described in detail below.
The credit facility generally prohibits Dynegy Inc. and its subsidiaries, including us, subject to various customary and other exceptions, from incurring additional debt. Notwithstanding this restriction, we may issue “exchange debt,” or debt issued in exchange for our outstanding senior unsecured debt. Any such exchange debt may provide for guarantees that result in such debt being structurally senior to our outstanding senior unsecured debt. Any exchange debt issued would be subject to the following restrictions:
•
for exchange debt offered in respect of our senior unsecured debt maturing in 2005 and 2006,
•
if the maturity of the exchange debt is prior to March 15, 2007, then the aggregate principal amount of exchange debt issued generally cannot exceed 66% of the aggregate principal amount of our senior unsecured debt that is exchanged; and
•
if the maturity of the exchange debt is on or after March 15, 2007, then the aggregate principal amount of exchange debt issued generally cannot exceed the aggregate principal amount of our senior unsecured debt that is exchanged;
•
for exchange debt offered in respect of our senior unsecured debt maturing in 2011, 2012, 2018 and 2026,
•
the aggregate principal amount of exchange debt issued generally cannot exceed the aggregate principal amount of our senior unsecured debt that is exchanged; and
•
the maturity of the exchange debt must be after December 31, 2009; and
•
the aggregate cash interest expense of any exchange debt cannot exceed the aggregate cash interest expense of our senior unsecured debt that is exchanged.
The credit facility generally prohibits Dynegy Inc. and its subsidiaries, including us, from pre-paying, redeeming or repurchasing outstanding debt or preferred stock. Notwithstanding this restriction, Dynegy Inc. and its subsidiaries, including us, may repurchase or redeem up to $300 million in our senior notes or Dynegy Inc. Series B preferred stock held by ChevronTexaco subject to the following restrictions:
•
the first $100 million in repurchases of our senior notes requires a concurrent permanent reduction in commitments under the credit facility of $100 million, the second $100 million in repurchases requires a concurrent permanent reduction in commitments under the credit facility of $200 million, and the third $100 million in repurchases requires a concurrent permanent reduction in commitments under the credit facility of $300 million;
•
no concurrent permanent reduction in commitments under the credit facility is required if our senior notes are repurchased with net cash proceeds attributable to extraordinary receipts or the issuance of equity or subordinated debt; and
•
only $50 million of the $300 million may be used to repurchase our senior notes that mature on or after April 1, 2011; and
•
only $50 million of the $300 million may be used to redeem shares of the Dynegy Inc. Series B preferred stock held by ChevronTexaco, and Dynegy Inc. must permanently reduce commitments under the credit facility concurrently by three times the amount used to redeem such shares.
Notwithstanding the foregoing, Dynegy Inc. must have $500 million of liquidity for ten days prior to and as of the date of the repurchase or redemption of our senior notes or the Dynegy Inc. Series B preferred stock.
The financial covenants in the credit facility are described below. Dynegy Inc. and its subsidiaries, including us but excluding IP and DGC and their respective subsidiaries, are prohibited from:
•
permitting their Secured Debt/EBITDA Ratio (as defined in the credit facility) from and after September 30, 2003 to be greater than the ratio set forth below:
•
the definition of EBITDA in the credit facility specifically excludes, among other items, (i) discontinued business operations (including third-party marketing and trading, communications and tolling arrangements), (ii) disclosed litigation, (iii) extraordinary gains or losses, (iv) any impairment, abandonment, restructuring or similar non-cash expenses, and (v) turbine cancellation payments up to $50 million in the aggregate;
•
permitting their liquidity to be less than $200 million for a period of more than ten consecutive business days; or
•
making capital expenditures during the four fiscal quarter period ending on the applicable dates set forth below in an amount exceeding the amount set forth opposite such fiscal quarter:
•
making capital expenditures in connection with the completion of the Rolling Hills facility in an aggregate amount exceeding $85 million.
With respect to the quarterly restrictions on capital expenditures set forth above, Dynegy Inc. may (i) carry forward any amount not expended in the four fiscal quarter period in which it was permitted and (ii) carryback up to 50 percent of any amount permitted in a future four fiscal quarter period to any prior four fiscal quarter period and the amount related to the future four fiscal quarter period will be reduced accordingly. Further, Dynegy Inc. and its subsidiaries, including us, may make additional capital expenditures that are required to comply with applicable law.
The credit facility contains events of default relating to:
•
non-payment of principal when due, non-payment of interest or any commitment fee within three days or non-payment of any other amounts payable under applicable loan documents within five business days;
•
failure to comply with specified covenants and agreements, subject to applicable grace periods;
•
incorrect or materially misleading representations or warranties when made;
•
specified defaults under (i) any debt or guarantee obligation having an aggregate principal amount in excess of $50 million or (ii) certain swap contracts with a termination value owed to the counterparty in excess of $50 million;
•
specified insolvency proceedings that are not discharged or stayed within 60 days or the inability to pay debts as they become due;
•
the entry of a final, non-appealable judgment in excess of $50 million (net of insurance) that is not discharged or stayed within 60 days;
•
specified ERISA-related events involving in excess of $50 million; and
•
any change of control.
Upon the occurrence of any event of default, upon the request of lenders representing more than 50 percent of borrowings outstanding under the credit facility, such lenders may, among other things, declare all borrowings outstanding (including letters of credit) under the credit facility immediately due and payable.
The foregoing description of the material terms of our new credit facility and related ancillary documents is qualified in its entirety by reference to the definitive agreements governing the credit facility, which are included as exhibits to this Form 10-K.
Debt Obligations. The following chart depicts our consolidated third-party debt obligations, including our DNE leveraged lease, relative to the primary entity under which those obligations reside as of April 2, 2003 (in millions):
The following table lists our third-party debt obligations, including our DNE leveraged lease, as of April 2, 2003, indicating whether such obligations are secured or unsecured (in millions):
(1)
Includes $405 million in letters of credit outstanding.
(2)
This approximately $6.0 billion in debt obligations reconciles to the approximately $3.8 billion in Long-Term Debt and Notes Payable and Current Portion of Long-Term Debt included in our Consolidated Balance Sheets as follows (in millions):
(3)
Represents the present value of future lease payments using a 10 percent discount rate.
Debt Maturities. The restructuring and extension of our bank credit facilities has substantially reduced our 2003-2004 maturities.
The following tables list our quarterly debt maturities through 2005 as of April 2, 2003 (amounts are approximated and presented in millions):
(1)
Reflects required quarterly payments under Dynegy’s Black Thunder financing as further described in Item 8, Financial Statements and Supplementary Data, Note 10-Debt beginning on page.
(2)
Reflects required payments associated with Project Alpha as further described in Item 8, Financial Statements and Supplementary Data, Note 10-Debt beginning on page.
(3)
We recently agreed to prepay this $106 million on April 16, 2003.
(4)
Includes $405 million of outstanding letters of credit.
Off-Balance Sheet Arrangements
As previously disclosed, in mid-2002 we restructured our Black Thunder minority interest transaction, which resulted in the reclassification of $796 million from Minority Interest to debt on our Consolidated Balance Sheet. We also voluntarily undertook specific actions, the effect of which altered the accounting for one of our lease obligations. As a result of those actions, together with accounting restatements we recently made affecting the accounting treatment of these and other similar arrangements, we now have one remaining off-balance sheet financing.
DNE Leveraged Lease. As described in Item 1, Business-Power Generation beginning on page 4, we acquired the DNE power generating facilities in January 2001 from Central Hudson Gas & Electric Corporation, Consolidated Edison Company of New York, Inc. and Niagara Mohawk Power Corporation. These facilities consist of a combination of base-load, intermediate and peaking facilities aggregating 1,700 MW and are located in Newburgh, New York, approximately 50 miles north of New York City. The aggregate purchase price for the facilities was approximately $950 million and included a transitional obligation to provide power to Central Hudson through October 2004. In May 2001, we sold four of the six generating units comprising these facilities to an unrelated third-party investor for approximately $920 million and concurrently agreed to lease them back from that investor. The third-party investor provided $138 million in equity funding and received $800.4 million of proceeds from a private offering of pass-through trust certificates by two of our subsidiaries to purchase the facilities and pay transaction expenses. 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, 2002, future lease payments are $60 million for each year 2003 through 2006, with $1.3 billion in the aggregate due during the period 2007 through lease expiration. The Roseton lease expires on February 8, 2035 and the Danskammer lease expires on May 8, 2031. DHI has guaranteed the lessees’ payment and performance obligations under their respective leases on a senior unsecured basis. At December 31, 2002, the present value (discounted at 10%) of future lease payments was $763 million.
We entered into the leveraged lease transaction to provide long-term financing for our acquisition of these facilities, which established our physical presence as a generator in the Northeastern region of the United States. The following table sets forth our lease expenses and lease payments relating to these facilities for the periods presented.
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, we would be required to make a termination payment in an amount sufficient to redeem the pass through trust certificates related to the unit or facility for which the lease was terminated at par plus accrued and unpaid interest. The current termination payment at par would be $999 million. 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, we would be required to redeem the related pass through trust certificates at par plus a make-whole premium.
Interest Expense
We have recognized interest expense of $228 million, $143 million and $96 million for the years 2002, 2001 and 2000, respectively. Our interest expense in 2003 and thereafter will reflect the increased cost of borrowing in our restructured credit facility. Generally, borrowings under the restructured credit facility will bear interest, at our option, at (i) a base rate plus 3.75% per annum or (ii) LIBOR plus 4.75% per annum. Pricing on letters of credit has increased from approximately 50 basis points under our former $400 million credit facility and 200 basis points under our former $900 million credit facility to approximately 475 basis points under the restructured credit facility. Further contributing to our anticipated increase in interest expense in 2003 is our expectation that we will issue letters of credit in support of our marketing and trading obligations, which will be outstanding for the full year, as compared to the similar requirements that we faced beginning in mid-2002. We anticipate that we will recognize net interest expense of approximately $432 million in 2003.
Operating Cash Flows
Our net cash flows from operations for the years 2002, 2001 and 2000 were $26 million, $176 million and $408 million, respectively. As discussed above, we posted significant amounts of collateral, particularly in the latter half of 2002, to support our marketing and trading and asset-based businesses. The amount of cash collateral posted increased from less than $1 million at the end of 2001 to $319 million at the end of 2002. This increase is reflected in the cash flow statement as a reduction in operating cash flow. Operating cash flow in 2002 was also negatively impacted during 2002 by the factors that negatively affected our results of operations, particularly low power prices and decreased liquidity in trading markets. Please read “-Results of Operations” beginning on page 48 for further discussion.
We expect that our exit from the third-party marketing and trading business will result in benefits to operating cash flow in 2003, particularly with respect to gas inventories held in storage that were sold in the first quarter. Our operating cash flows in 2003 and thereafter also will continue to reflect the expected negative cash flow associated with our eight power tolling arrangements. Please read “-Results of Operations-Wholesale Energy Network-WEN Outlook” beginning on page 55 for further discussion of these arrangements. The cash flow of our asset-based operations will be significantly affected by the price realized for power and the relationship of prices for power and for natural gas or other generating fuels.
Disclosure of Financial Obligations and Contingent Financial Commitments
We have incurred various financial obligations and commitments in the normal course of our operations and financing activities. Financial obligations include future cash payments required under existing contractual arrangements, 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 revenue-producing activities. Financial commitments represent contingent obligations, which become payable only if certain pre-defined events occur, such as financial guarantees.
The following table provides a summary of our general financial obligations as of December 31, 2002. This table includes cash obligations related to outstanding debt, redeemable preferred stock and similar financing transactions. This table also includes cash obligations for minimum lease payments associated with general corporate services, such as office and equipment leases.
General Financial Obligations as of December 31, 2002
*
Cash obligations herein are not discounted and do not include related interest, accretion or dividends.
(1)
Total amounts are included in the December 31, 2002 Consolidated Balance Sheet. For additional explanation, please read Item 8, Financial Statements and Supplementary Data, Note 10-Debt beginning on page.
(2)
Includes minimum lease payment obligations associated with office and office equipment leases.
The following table provides a summary of our contingent financial commitments as of December 31, 2002. These commitments represent contingent obligations that may require a payment of cash upon certain pre-defined events.
Contingent Financial Commitments as of December 31, 2002
*
Contingent obligations are presented on an undiscounted basis.
(1)
Amounts include outstanding letters of credit and uncommitted credit lines.
(2)
Surety bonds are generally on a rolling twelve-month basis.
(3)
Amounts include a $70 million residual value guarantee related to the Tilton lease arrangement. Based on the current estimated fair value of the underlying assets, we do not anticipate funding such amounts. Amounts also include two lease arrangements relating to VLGCs utilized in the DMS Segment that have been subchartered to a wholly owned subsidiary of Transammonia Inc. for the remaining lease term in connection with the sale of the global liquids business.
The table set forth below provides a summary of our commercial financial obligations, which are generally associated with revenue-producing activities. These arrangements provide us access to third-party owned assets for use in our asset-based lines of business. These obligations include certain unconditional purchase obligations associated with generation turbines and minimum lease payments associated with operating leases on assets used in our power generation and natural gas liquids businesses. The obligations also include capacity payments under power tolling arrangements and transportation, transmission and storage arrangements.
As described elsewhere in this annual report, we are in the process of exiting from third-party risk-management aspects of the marketing and trading business. Approximately $3.8 billion of the “Capacity Payments” included below represents the future value of capacity payments pursuant to the power tolling arrangements described in Item 1. Business-Customer Risk Management beginning on page 16. The discounted value of these payments (based on a LIBOR-based discount rate) totaled $2.7 billion. Based on current estimates, the discounted fair value of the capacity payments under these arrangements exceeded the market value of electricity available for sale under these arrangements at December 31, 2002 by approximately $501 million. This amount includes tolling payments that are reflected at fair value on our Consolidated Balance Sheet in “Risk-Management Assets” or “Risk-Management Liabilities” for those contracts that are accounted for using mark-to-market accounting as well as amounts relating to contracts that are accounted for on an accrual basis, each as determined by the applicable contractual terms and in accordance with generally accepted accounting principles. At December 31, 2002, approximately 70 percent of the $3.8 billion of aggregate tolling capacity payments are accounted for on an accrual basis and approximately three-fourths of the $501 million noted above is attributable to contracts accounted for under the accrual method. Upon the adoption of EITF 02-03, as more fully described in Note 2 to the consolidated financial statements starting on page, substantially all of our tolling arrangements will be accounted for on an accrual basis beginning January 1, 2003. We will continue our efforts to renegotiate or terminate some of these arrangements, which we will account for going forward in our CRM segment. Please read “-Results of Operations-WEN Outlook” beginning on page 55 for further discussion of the anticipated effects of these arrangements on our future results of operations.
Commercial Financial Obligations as of December 31, 2002
*
Cash obligations are presented on an undiscounted basis.
(1)
Amounts include the minimum lease payment obligations associated with the lease arrangements relating to our DNE generation facilities and our Tilton generating facility.
(2)
Amounts include natural gas, coal, systems design, various maintenance agreements and power purchase agreements.
(3)
Capacity payments include future values of payments aggregating $3.8 billion under our power tolling arrangements. Other capacity payments totaling approximately $595 million include fixed obligations associated with transmission, transportation and storage arrangements.
(4)
Amounts include our obligations as of December 31, 2002 to purchase 14 gas-fired turbines. Commitments under the turbine purchase orders are payable consistent with the delivery schedule. The purchase orders include milestone requirements by the manufacturer and provide us with the ability to cancel each discrete purchase order commitment in exchange for a fee, which escalates over time. The amounts herein assume all 14 turbines will be purchased. However, we can cancel these arrangements at any time, subject to a termination fee. If we had terminated the turbine purchase orders at December 31, 2002, the termination fee would have been approximately $48 million, reducing our conditional purchase commitment by $435 million. During the first quarter 2003, we renegotiated these turbine commitments. Under the new arrangements, cash obligations total $6 million in 2003, zero in 2004, $147 million in 2005, $193 million in 2006, $113 million in 2007 and $24 million in 2008. The termination payment remains at approximately $48 million through the first quarter 2004 and is subject to variable escalation thereafter.
We have entered into various joint ventures principally for the purpose of sharing risk or to optimize existing commercial relationships. These joint ventures maintain independent capital structures and have financed their operations on a non-recourse basis to us. Please read Item 8, Financial Statements and Supplementary Data, Note 8-Unconsolidated Investments, beginning on page, for further discussion of these joint ventures.
Capital Spending
The 2003 capital budget of $271 million primarily includes construction projects in progress, maintenance capital projects, environmental projects, contributions to equity investments and limited discretionary capital investment funds. The capital budget is subject to revision as opportunities arise or circumstances change. Funds budgeted for the aforementioned items by the various segments in 2003 are as follows:
2003 Budgeted Capital Expenditures
Included within the Power Generation segment’s capital budget are $60 million of funds to complete the Rolling Hills power plant, which is currently under construction and expected to begin commercial operation during the second quarter 2003. This natural gas-fired facility, located in Ohio, will provide 838 MW of generation capacity.
Our capital expenditures in 2003 and beyond will be limited by negative covenants contained in our restructured credit agreements. These covenants place specific dollar limitations on our ability to incur capital expenditures. Please read “-Bank Restructuring” beginning on page 34 for further discussion.
During 2002, our actual capital expenditures were as follows:
2002 Actual Capital Expenditures
Capital spending during 2002 for the WEN segment related primarily to our generation assets, the most significant of which were approximately as follows:
•
Rolling Hills-$195 million;
•
Wood River-$52 million;
•
Baldwin-$51 million;
•
Renaissance-$46 million;
•
Bluegrass-$33 million;
•
Foothills-$28 million; and
•
Various other generation asset-related investments aggregating $149 million.
DMS segment capital expenditures of approximately $94 million were primarily related to gas plants and liquids marketing assets, the most significant of which were $29.2 million for the expansion of the Chico gas plant, $7.8 million at the Cedar Bayou fractionator, $6.9 million at the Mont Belvieu terminal and $6.3 million for the Hackberry LNG project, which we have agreed to sell to Sempra.
Transmission and distribution capital expenditures included $11 million related to Northern Natural.
Other consists of spending on information technology.
Credit Rating Discussion
Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing and the execution of our commercial strategies in a cost-effective manner. In determining our credit ratings, the rating agencies consider a number of factors. Quantitative factors that management believes are given significant weight include, among other things, EBITDA; operating cash flow; total debt outstanding; off balance sheet obligations and other commitments; fixed charges such as interest expense, rent or lease payments; distributions to stockholders; liquidity needs and availability and various ratios calculated from these factors. Qualitative factors appear to include, among other things, predictability of cash flows, business strategy, industry position,
quality of management, equity value, litigation, regulatory investigations and other contingencies. Although these factors are among those considered by the rating agencies, each agency may calculate and weigh each factor differently.
Our credit ratings were lowered several times during 2002 by each of the major credit rating agencies. In taking these actions, including those made subsequent to the announcement of our capital plan, the rating agencies generally cited concerns over, among other things, the level of cash flows that we will be able to generate from our continuing businesses relative to our significant financial leverage, our ability to address our substantial near-term debt maturities, uncertainties surrounding our ongoing litigation and government investigations and the restatement of our 1999-2001 financial statements and the likelihood that the renewal of our revolving credit facilities would require a granting of collateral that would subordinate the unsecured bond holders. Most recently, on March 10, 2003, Fitch lowered its ratings on Dynegy Inc. and its subsidiaries, including us, indicating that the downgrades anticipated the successful renewal and restructuring on a secured basis of our maturing credit facilities and U.S. communications network financing. Currently, our credit ratings are at least six notches below investment grade at Standard & Poor’s, Moody’s and Fitch. Additionally, our ratings remain on negative watch for further downgrade by both Standard & Poor’s and Fitch; Moody’s currently rates us with a negative outlook.
As of April 2, 2003, our senior unsecured debt ratings, as assessed by the three major credit rating agencies, were as follows:
Rated Enterprises
Standard & Poor’s
Moody’s
Fitch
Senior Unsecured Debt Rating
CCC+
Caa2
CCC+
While we have substantially improved our liquidity position during the past several months and have made progress toward resolving many of the concerns cited by the rating agencies, we cannot be assured that our credit ratings will be improved. Our current, non-investment grade ratings have adversely affected our ability to access the capital markets and caused us to incur increased costs, including the granting of security, and more restrictive covenants in our recent refinancing activities. Should our ratings continue at their current levels, or should we be further downgraded, we would expect these negative effects to continue and, in the case of a downgrade, perhaps become more pronounced.
Financing Trigger Events
Our debt instruments and other financial obligations include routine 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, changes in law resulting in loss of tax-exempt status on certain bond issuances, 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 have not executed any transactions that require us to issue equity based on credit rating or other trigger events.
Commitments and Contingencies
Please read Item 8, Financial Statements and Supplementary Data, Note 14, beginning on page, which is incorporated herein by reference, for a discussion of our commitments and contingencies.
FACTORS AFFECTING FUTURE OPERATING RESULTS
Our results of operations in 2003 and beyond may be significantly affected by the following factors, among others:
•
the level of earnings and cash flows from our continuing asset-based businesses, which are subject to the effect of changes in commodity prices, particularly for power and the relationship between prices for power and for natural gas or other generating fuels, commonly referred to as the “spark spread”;
•
the negative cash flow expected from our tolling agreements and the effect that changes in power prices might have on our non-cash mark-to-market earnings associated with these arrangements;
•
our substantial level of leverage, which was reflected in approximately $4.7 billion of total debt and $405 million in letters of credit posted by us at April 2, 2003;
•
higher interest expense resulting from increased demand for collateral in our asset based businesses and higher cost of borrowing under new credit agreements;
•
the effects of ongoing investigations and litigation relating to, among other things, our past trading practices, our activities in the California power market, shareholder claims against Dynegy Inc. and claims arising out of our legacy CRM business;
•
our ability to operate our business within the confines of the increased borrowing rates and more restrictive covenants contained in our restructured bank credit facilities;
•
our ability to access the capital markets given our non-investment grade credit ratings; and
•
our ability to operate our business with a decentralized organizational structure and a reduced workforce.
Additionally, new accounting pronouncements will also impact our reported results of operations going forward. For example, during 2002, the EITF discussed Issue No. 02-03, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” and reached consensus on certain issues. EITF Issue 02-03 rescinds EITF 98-10, which required that energy trading contracts be accounted for at fair value, effective for any new contracts entered into after October 25, 2002. For energy trading contracts entered into through October 25, 2002, we continue to account for such contracts at fair value through December 31, 2002. Effective January 1, 2003, contracts that do not meet the accounting definition of derivatives are required to be accounted for under the accrual method and we will report all previously recorded unrealized income on these contracts as a cumulative effect of an accounting change. Our energy trading contracts that qualify as derivatives will continue to be accounted for at fair value under Statement No. 133. Please read Item 8, Financial Statements and Supplementary Data, Note 5-Commercial Operations, Risk Management Activities and Financial Instruments, beginning on page for further discussion.
In addition, we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” effective as of January 1, 2003. Under Statement No. 143, asset retirement obligations are to be recorded at fair value in the period in which they are incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the related assets. As part of the transition adjustment in adopting Statement No. 143, certain existing environmental liabilities are required to be reversed upon adoption. As we had previously accrued environmental liabilities of approximately $73 million for which remediation can be delayed until asset retirement, such liabilities have been reversed as a component of the cumulative effect adjustment in adopting Statement No. 143. As such, we expect the impact of our adoption of Statement No. 143 will be an increase to earnings, net of tax, of approximately $33 million in the first quarter 2003 to be reflected as a cumulative effect of a change in accounting principle. The annual amortization of the assets created under this standard and the accretion of the liability to its fair value is estimated to be approximately $6 million in 2003.
Please read “Uncertainty of Forward Looking Statements and Information” beginning on page 66 for additional factors that could impact our future operating results.
RESULTS OF OPERATIONS
In this section, we discuss our results of operations, both on a consolidated basis and by segment, for the years 2002, 2001 and 2000. With respect to our segment results for these periods, we have presented the results for our three reportable business segments during the three-year period:
•
Wholesale Energy Network;
•
Dynegy Midstream Services; and
•
Transmission and Distribution.
As described above under Item 1 - Business beginning on page 2, we will report our operations in the following segments for 2003:
•
Power generation;
•
Natural gas liquids; and
•
Customer risk management.
Other reported results will include corporate overhead. This change in reportable segments will affect the comparability of our future segment results.
Regarding our results of operations for 2002, 2001 and 2000, the impact of acquisition and disposition activity during the three-year period reduces the comparability of some of our historical financial and volumetric data.
Recent accounting pronouncements have also affected our financial results, particularly those of our third-party marketing and trading business, so as to further reduce the comparability of some of our historical financial data. For example, pursuant to EITF Issue 02-03, all mark-to-market gains and losses on energy trading contracts whether realized or unrealized, are shown net in the income statement, irrespective of whether the contract is physically or financially settled. In addition, pursuant to the transition provisions in EITF Issue 02-03, we have conformed the comparative period financial information contained in this annual report to reflect this change in accounting principle. We have historically classified net unrealized gains and losses from energy trading contracts as revenue in our consolidated statement of operations. However, physical transactions that were realized and settled were previously reflected gross in revenues and costs of sales. This change in accounting classification has no impact on our operating income, net income, earnings per share or operating cash flows.
For segment reporting purposes, all general and administrative expenses incurred by us on behalf of our subsidiaries have been charged to the applicable subsidiary as incurred. We have allocated indirect general and administrative expenses to our subsidiaries using a two-step formula that considers both payroll expense and total assets. Interest expense incurred by us on behalf of our subsidiaries has been allocated based on the subsidiaries’ capital structure. Other income (expense) items incurred by us on behalf of our subsidiaries are allocated equally among sub-components of our business segments.
The historical information presented below has been revised to reflect the restatement items otherwise contained in Amendment No. 1 to our 2001 Form 10-K, which we have filed with the SEC concurrently with this annual report. As further described in Item 8, Financial Statements and Supplementary Data, Note 19-Quarterly Financial Information (Unaudited) beginning on page, these restatements relate to the following items:
•
the Project Alpha structured natural gas transaction,
•
a balance sheet reconciliation project relating principally to our natural gas marketing business,
•
corrections to our previous hedge accounting for certain contracts resulting in our accounting for these contracts pursuant to the mark-to-market method under Statement No. 133; in addition, we determined that we had incorrectly accounted for certain derivative transactions prior to the adoption of Statement No. 133,
•
the restatement of our forward power curve methodology to reflect forward power and market prices more closely,
•
the recognition of additional assets, accrued liabilities and debt associated with certain lease arrangements, as well as depreciation and amortization expense for the related assets,
•
the recognition of an other-than-temporary decline in value of a technology investment in the third quarter of 2001 rather than the second quarter of 2002,
•
corrections to our previous accounting for income taxes, and
•
other adjustments that arose during the re-audit of our 1999-2001 financial statements.
While certain of these items arose as the result of our consideration of differing interpretations of the applicable GAAP requirements between our former and current independent auditors, others, such as the restatements relating to Project Alpha, the natural gas marketing charge, hedge accounting under Statement No. 133 and our previous accounting for income taxes, resulted from accounting errors. Please read Item 14, Controls and Procedures, beginning on page 72 for discussion of the measures we are taking relative to our internal control environment.
Three Years Ended December 31, 2002
The following table provides summary financial data regarding our consolidated results of operations for 2002, 2001 and 2000, respectively.
Results of Operations
Net Income (Loss). We incurred a net loss of $1,246 million in 2002. This compares with net income of $425 million and $398 million in 2001 and 2000, respectively. The following significant items contributed to our net loss for 2002:
•
a charge of $724 million for the impairment of goodwill associated with our WEN segment;
•
an after-tax loss of $23 million on our discontinued operations, primarily due to an after-tax loss of approximately $45 million on the sale of Northern Natural;
•
after-tax charges totaling approximately $135 million relating to our corporate restructuring and related workforce reductions;
•
an after-tax charge of approximately $76 million related to the impairment of some of our generation investments;
•
other charges primarily associated with asset write-offs, losses on asset sales, contract and litigation settlements and the recognition of additional reserves.
In addition to these significant items, a weak pricing environment, especially for power, and reduced market liquidity contributed to lower operating results in 2002. Please read our segment discussions below for further discussion of the changes in operating income during the periods presented.
Our 2001 net income increased to $425 million from $398 million in 2000. The following significant items impacted our 2001 results on an after-tax basis as follows:
•
approximately $84 million related to energy sales to Enron and its affiliates, which filed for bankruptcy during the fourth quarter 2001; and
•
approximately $7 million associated with costs incurred in connection with the terminated Enron merger.
These charges, together with increased interest expense, partially offset the $150 million pre-tax increase in operating income period over period.
Our 2000 net income of $398 million included aggregate gains of approximately $92 million associated with the sale of Accord and some QFs. These gains were partially offset by losses on sales of our crude oil business and our Mid-Continent gas processing assets, the impairment of a Canadian liquids asset and costs incurred in connection with our acquisition of Illinova.
The following table sets forth significant items affecting net income for the periods presented.
(1)
Includes various charges incurred in 2002, including the write-off of Dynegydirect, our former electronic trading platform, which resulted in an after-tax charge of approximately $16 million ($25 million pre-tax).
Equity Earnings. Our share in the earnings (losses) of our unconsolidated investments, contributed losses of approximately $54 million in 2002 and earnings of approximately $178 million and $191 million in 2001 and 2000, respectively. West Coast Power contributed approximately $17 million, $162 million and $122 million to equity earnings in 2002, 2001 and 2000, respectively. The decrease in earnings from West Coast Power in 2002 is due in part to a reduction in contingent capacity and energy sales under the CDWR contract. Please read Item 1, Business beginning on page 2 for further discussion of this contract. Equity earnings from West Coast Power also include a pre-tax charge of $50 million ($33 million after-tax) related to our share of a reserve taken by West Coast Power to increase its allowance for doubtful accounts. The overall decrease in equity earnings in 2002 was primarily due to significant impairments of generation and technology investments recognized during 2002.
The increase in equity earnings in 2001 from 2000 primarily reflects returns on investments in regionally diverse power generation joint ventures that benefited from higher power prices. Cash distributions received from all unconsolidated investments in 2002, 2001 and 2000 approximated $77 million, $87 million and $109 million, respectively.
Interest Expense. Interest expense totaled $228 million for 2002, compared with $143 million and $96 million for 2001 and 2000, respectively. The increase in interest expense in 2002 was due primarily to increased principal borrowed to support our liquidity needs in 2002. Specifically, these additional principal amounts primarily relate to cash borrowings and letters of credit under our revolving credit facilities used to satisfy counterparty collateral demands. The effect of the increased interest expense relating to these additional principal amounts was partially offset by lower variable rates than in 2001. The increase in interest expense in 2001 from 2000 was due primarily to increased principal, partially offset by lower variable rates than in 2000.
Other Items. Net other income and expenses, net reduced 2002, 2001 and 2000 operating results by $57 million, $51 million and $87 million, respectively. The 2002 results were negatively impacted by the following:
•
a charge of $16 million ($25 million pre-tax) associated with the settlement of the Enron litigation;
•
a charge of $15 million ($22 million pre-tax) relating to the cancellation of our natural gas purchases and sales contract with ChevronTexaco;
•
a charge of $4 million ($6 million pre-tax) associated with fees related to a voluntary action that we took that altered the accounting for some of our lease obligations;
•
a charge of $5 million related to our settlement with the CFTC; and
•
a charge of $3 million related to our settlement with the SEC.
The remaining net amounts for all three years include the financial effects of minority shareholder investments in some of our operations, including interest and dividend income, foreign currency gains and losses, insurance proceeds and other similar items.
Income Tax (Provision) Benefit. We reported an income tax benefit of $335 million in 2002, compared to income tax provisions of $313 million and $212 million in 2001 and 2000, respectively. These amounts reflect effective rates of 22 percent, 43 percent and 35 percent, respectively. In general, differences between these effective rates and the statutory rate of 35 percent result primarily from permanent differences attributable to book-tax differences and certain liabilities, and the effect of certain foreign and state income taxes. In addition, the 2002 effective rate was impacted significantly by the $724 million goodwill impairment relating to the WEN segment. As there was no tax basis in the asset, there was no tax benefit associated with the charge. See Item 8, Financial Statements and Supplementary Data, Note 12 beginning on page, which is incorporated herein by reference, for further discussion of our income taxes.
Discontinued Operations. Discontinued operations primarily include Northern Natural, our global liquids business, and our U.K. natural gas storage assets. On August 16, 2002, Dynegy Inc. sold Northern Natural to MidAmerican for $879 million in cash, after adjustment for working capital changes. MidAmerican acquired all of the common and preferred stock of Northern Natural and assumed all of its $950 million of debt. We incurred a loss of approximately $45 million ($63 million pre-tax) associated with the sale of Northern Natural’s common stock, including the final adjustment for working capital changes. During 2002, we also recognized an after-tax charge of approximately $12 million associated with the impairment of an LPG investment in the global liquids business.
Segment Results of Operations
Wholesale Energy Network
WEN reported a segment net loss of $1,194 million for 2002, compared with net income of $369 million and $372 million for 2001 and 2000, respectively. Results of operations during the three-year period were influenced either positively or negatively by the following:
•
decreased equity earnings from West Coast Power from 2001 to 2002 as a result of lower volumes sold, an impairment of our investment and an increase in the allowance for West Coast Power’s doubtful accounts;
•
charges relating to our impairment of goodwill and generation equity investments in 2002;
•
reduced gas marketing volumes during 2002 as a result of reduced market liquidity and our lower credit ratings;
•
a weak pricing environment, particularly for power, causing reduced earnings from our generation facilities in 2002;
•
increased earnings resulting from additional power generating capacity acquired or placed in service in 2002, 2001 and 2000;
•
increased equity earnings from West Coast Power from 2000 to 2001, partially attributable to higher price realization for power purchased from West Coast Power;
•
an increase in customer and risk-management activities in 2001, as compared to 2000, as a result of a long-term power agreement that contributed approximately $35 million of non-cash earnings in 2001;
•
an increase in European and Canadian marketing operations due to increased customer origination and service demand during 2000 and 2001;
•
an approximate $82 million after-tax charge relating to exposure to Enron as a result of that company’s bankruptcy filing and an allocation of transaction costs associated with the terminated merger with Enron and the execution of Project Alpha in 2001; and
•
aggregate after-tax gains of approximately $92 million on the sales of Accord and some of our QFs, offset by an allocated portion of Illinova acquisition costs, in 2000.
The new generating capacity in 2002 included the Renaissance, Bluegrass and Foothills facilities aggregating 1,512 MW. The new generating capacity in 2001 included the DNE power generating facilities in New York and development projects in Georgia, Kentucky and Louisiana aggregating 2,865 MW. The new capacity in 2000 included the generation assets from the Illinova acquisition and development projects in Illinois, Louisiana and North Carolina aggregating 8,091 MW.
Total electric power produced and sold during 2002 aggregated 415.6 million megawatt hours compared to 361.8 million and 137.0 million megawatt hours during 2001 and 2000, respectively. Volumes for each period reflect the impact of additional generating capacity. Total natural gas volumes sold decreased to 11.9 billion cubic feet per day in 2002 from 12.5 billion cubic feet per day in 2001 and 10.9 billion cubic feet per day in 2000. The 2001 increase in natural gas volumes sold reflects greater market origination, including sales to commercial and industrial customers, sales volumes on Dynegydirect and increased gas marketing in Canada. The decrease in volumes in 2002 reflects market liquidity and credit concerns.
WEN Outlook
As described in Item 1. Business beginning on page 2, our former WEN segment will be reported in two segments in 2003-Power Generation, which will hold our power generation facilities and related assets, and Customer Risk Management, which will hold the third-party marketing and trading business from which we are exiting, including our eight remaining long-term power tolling arrangements. With respect to our power generation business, we expect that its future financial results will continue to reflect a sensitivity to weather, power and natural gas prices, including the spark spread, and terms of contracts for contracted generation. We believe that our generation fleet’s fuel diversity will help mitigate the extent to which this segment’s future results are affected by changes in natural gas prices. We also expect that this business will continue its efforts to manage its price risk through the optimization of fuel procurement and the marketing of power generated from its assets. As part of our strategy of commercially optimizing our assets, including agency and energy management agreements to which we are a party, we enter into financial and other transactions including forward hedges relating to our generating capacity. This segment’s sensitivity to prices and our ability to manage this sensitivity is subject to a number of factors, including general market liquidity, our ability to provide necessary collateral support and the willingness of counterparties to transact business with us given our non-investment grade credit ratings. Other factors that could affect the prices at which transactions can be consummated and this segment’s results of operations include transmission contracts, or the lack thereof, and governmental actions or excess generation capacity in the markets we serve.
Any events that negatively impact our significant long-term power sales agreements could likewise affect this segment’s future results of operations. For example, equity earnings from West Coast Power are primarily derived from West Coast Power’s long-term power sales contract with the CDWR. That contract, which runs through December 31, 2004, is the subject of various legal challenges as further described in Note 14- Commitments and Contingencies beginning on page. The success of any such challenges would negatively impact this segment’s equity earnings from West Coast Power and, accordingly, its results of operations for the periods affected.
Our CRM business’ future results of operations will be significantly impacted by our ability to execute on our exit strategy. We are actively pursuing opportunities to assign or renegotiate the terms of our contractual obligations related to this business, particularly some of our power tolling arrangements. While we expect to complete a significant portion of our exit activities during the first half of 2003, some contracts, particularly our power tolling contracts, do not expire for up to 30 years and credit and market liquidity constraints could impact our ability to complete our exit plan and the timing thereof. If we are unsuccessful in our efforts to renegotiate or terminate some of the eight power tolling arrangements to which we remain a party, we would be required to pay an aggregate of approximately $3.8 billion in capacity payments under the related agreements through 2030, including $226 million in 2003 and $229 million in 2004. After applying a LIBOR-based discount rate, these capacity payments approximate $2.7 billion. The discounted fair value of the capacity payments under these arrangements exceeded the market value of electricity available for sale under these arrangements at December 31, 2002 by approximately $501 million. Even if we were successful in our efforts to renegotiate or terminate some of these arrangements, we could incur significant expenses relating to any such renegotiation or termination.
In addition, we have posted collateral to support a substantial portion of our obligations in this business, including approximately $121 million at April 2, 2003 posted in connection with some of our power tolling arrangements. While we have been working with various counterparties to provide mutually acceptable collateral or other adequate assurance under these contracts, we have not reached agreement with Sithe Independence and Sterlington Quachita Power LLC regarding a mutually acceptable amount of collateral. Although we are current on all contract payments to these counterparties, we have received a notice of default from each such counterparty with regard to collateral. We are continuing to negotiate with both parties. Our annual net payments under these two arrangements approximate $67 million and $57 million, respectively, and the contracts extend through 2014 and 2012, respectively. If these counterparties were successful in pursuit of claims that we defaulted on these contracts, they could declare a termination of these contracts, which provide for termination payments based on the mark-to-market value of the contracts.
We have generally been successful in satisfying customer collateral requirements and have had few terminations or disputes relating to contracts in this segment. However, we are involved in litigation with some of our former counterparties relating to contract terminations with respect to which we were unable to agree on mutually acceptable collateral or other adequate assurance. There is a risk that we may be unable to agree with other counterparties on mutually acceptable forms and amounts of adequate assurance or other collateral, resulting in additional litigation and related expenses. Our ability to address these and other issues relating to collateral posted for ongoing CRM contracts will affect this business’ future results of operations.
We intend to manage actively our exit from the CRM business with the objective of maximizing the ultimate cash proceeds received and completing our exit plan in a timely and cost-effective manner. However, our failure to manage this exit successfully would negatively impact the CRM segment’s results of operations.
Dynegy Midstream Services
DMS reported a segment net loss of $30 million for 2002, compared with net income of $56 million and $26 million in 2001 and 2000, respectively. The following influenced this segment’s results of operations from 2002 compared to 2001:
•
a decline in processing plant margins caused by lower natural gas and realized NGL prices in 2002;
•
decreased profitability of our straddle plants in 2002 due to the negative effect of lower NGL prices and increased settlement costs related to volumes processed in 2002 that were processed on a slightly more profitable fee basis in 2001;
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reduced domestic and foreign marketing volumes and margins in 2002 as a result of slow economic recovery, high industry-wide inventory levels, reduced NGL liquidity and Dynegy-specific credit limitations;
•
$12 million of after-tax charges allocated to this segment during 2002 associated with our restructuring;
•
$7 million of after-tax charges allocated to this segment during 2002 relating to technology investment impairments, the Enron settlement and other items; and
•
the results of our discontinued operations in 2002, including a $12 million impairment of an LPG investment in India.
Results of operations from 2000 to 2001 were influenced either positively or negatively by:
•
Higher price realization in 2001, as compared to 2000, resulting from an active forward sales program and contract restructuring activities, despite a depressed pricing environment resulting from larger industry wide inventories;
•
Substantial focus on lowering costs throughout the two-year period;
•
Fluctuating world-wide demand for NGLs, particularly in Europe and Asia, enhanced 2000 revenues from global marketing operations;
•
Results for 2001 include approximately $2 million exposure to Enron (net of tax) as a result of that company’s bankruptcy filing and an allocation of transaction costs associated with the terminated proposed merger with Enron; and
•
Results for 2000 include losses of approximately $17 million (net of tax) on sales of the Crude Oil Marketing and Trade business (which was sold in April 2000 and contributed approximately $9 million after tax in 1999) and Mid-Continent gas processing assets, an impairment of approximately $16 million (net of tax) relating to Canadian gas processing assets and an allocation of costs related to the Illinova acquisition.
Aggregate domestic NGL fractionation volumes totaled 92 thousand gross barrels per day in 2002 compared to an average 84 thousand gross barrels per day and 97 thousand gross barrels per day in 2001 and 2000, respectively. Higher volumes processed in 2002 reflect volume growth from the Louisiana straddle plants and are the direct result of an increasing need to process Gulf of Mexico natural gas production to meet third-party downstream pipeline gas merchantability standards. In some cases, this has resulted in new contract terms that allow us to provide, on a temporary basis, processing services on a fee basis, thereby reducing our exposure to keep-whole processing margin risk. This is a trend that should continue as the volume of gas produced in the deep-water Gulf of Mexico increases. An increase in the volumes dedicated for processing by ChevronTexaco also contributed to the growth in Louisiana processing volumes during 2002. The reduction in volumes processed in 2001 compared to 2000 is due to the volume impacts from the sale of the Mid-Continent gas processing assets in 2000.
The average fractionation spread was $1.26 for 2002 compared to $0.89 and $2.40 in 2001 and 2000, respectively. Despite a slight increase in this spread in 2002, traditional keep-whole processing is still uneconomic at this level. Historically, the Louisiana straddle plants have not operated in this pricing environment.
DMS Outlook
We expect that the general industry-wide contraction in trade credit in the wholesale energy markets, including limitations relating to our own credit issues, will continue in 2003. This contraction is evidenced by the fact that open or unsecured credit lines are generally no longer available, and our customers are more stringent in requiring credit support in the form of cash in advance, letters of credit or guarantees as a condition to transacting business above open credit limits. Beginning in the second quarter 2002, and as a result of the general contraction of trade credit as well as downgrades in our credit ratings, DMS has been required to provide letters of credit and cash prepayments to collateralize our net exposure to various counterparties in its distribution and marketing business. During 2002, our marketing volumes were negatively affected by the general uncertainty in the energy and capital markets. We expect this market uncertainty to continue during the foreseeable future. Counterparty credit concerns and the resulting industry-wide contraction in trade credit have increased the cost of transacting business in the wholesale energy markets. As a result of this increase, we have generally refrained from entering into lower volume, lower margin transactions. We anticipate that this contraction in credit will continue to affect our marketing volumes, the number of transactions we enter into and the number of counterparties with whom we transact business.
Due to the turmoil in the Middle East and Venezuela, crude prices, liquids prices and natural gas prices are currently well above 2002 prices. If these price levels continue, we would expect this segment to generate higher profits than in 2002, all other factors being equal. Even at higher liquids prices, we are experiencing a weak fractionation spread environment. The correlation of prices for propane relative to prices for oil has returned to historical levels, improving expected revenues for this segment in the current pricing environment over 2002 when the correlation was lower than historical levels. Drilling activity by independent producers has been increasing in the past several months in the producing regions DMS serves due to higher commodity prices. Major producers are responding with more drilling activity in these regions, albeit more slowly, as their drilling programs are normally determined several years in advance.
Transmission and Distribution
The Transmission and Distribution segment was formed during 2002 and reflects the operations of Northern Natural. As a result of our sale of Northern Natural in the third quarter 2002, it is included in discontinued operations, as further discussed in Item 8, Financial Statements and Supplementary Data, Note 4-Restructuring and Impairment Charges beginning on page.
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 natural gas, electricity and NGLs. Power marketing operations and electricity generating facilities have higher volatility and demand, respectively, in the summer cooling months. These trends may change over time as demand for natural gas increases in the summer months as a result of increased gas-fired electricity generation. Our liquids businesses are also subject to seasonal factors; however, such factors typically have a greater impact on sales prices than on sales volumes.
CRITICAL ACCOUNTING POLICIES
Dynegy Inc.’s Controller’s Department is responsible for the development and application of accounting policy and control procedures for the organization’s financial and operational accounting functions. This department conducts its activities independent of any active management of our risk exposures, is independent of revenue-producing units and reports to its Chief Financial Officer.
The process of preparing financial statements in accordance with GAAP requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. We have identified the following six critical accounting policies that require a significant amount of judgment and are considered to be the most important to the portrayal of our financial position and results of operations as follows:
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Revenue Recognition;
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Valuation of Tangible and Intangible Assets;
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Estimated Useful Lives;
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Accounting for Contingencies; and
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Accounting for Income Taxes.
Revenue Recognition
We utilize two comprehensive accounting models in reporting our consolidated financial position and results of operations as required by GAAP - an accrual model and a fair value model. We determine the appropriate model for our operations based on guidance provided in applicable accounting standards and positions adopted by the FASB or the SEC. We have applied these accounting policies on a consistent basis during the three years in the period ended December 31, 2002, except as required by Financial Accounting Standard No. 133 (“FAS No. 133”), which was effective January 1, 2001, and the adoption of EITF 02-03, which rescinded EITF 98-10, “Accounting for Contracts Involved in Energy Trading and risk Management Activities.”
The accrual model has historically been used to account for substantially all of the operations conducted in our DMS and T&D segments as well as all physically operated assets owned by the WEN segment. These businesses consist largely of the ownership and operation of physical assets that we use in various generation, processing and delivery operations. These processes include the generation of electricity, the separation of natural gas liquids into their component parts from a stream of natural gas and the transportation or transmission of commodities through pipelines. End sales from these businesses result in physical delivery of commodities to our wholesale, commercial and industrial and retail customers.
The fair value model has historically been used to account for forward physical and financial transactions in the WEN and DMS segments, which meet criteria defined by the FASB or the EITF. The criteria are complex but generally require these contracts to relate to future periods, to contain fixed price and volume components and to have terms that require or permit net settlement of the contract in cash or the equivalent. The FASB determined that the fair value model is the most appropriate method for accounting for these types of contracts. In part, this conclusion is based on the cash settlement provisions in these agreements, as well as the volatility in commodity prices, interest rates and, if applicable, foreign exchange rates, which impact the valuation of these contracts. Since these transactions may be settled in cash, the value of the assets and liabilities associated with these transactions is reported at estimated settlement value based on current prices and rates as of each balance sheet date.
We estimate the fair value of our marketing portfolio using a liquidation value approach assuming that the ability to transact business in the market remains at historical levels. The estimated fair value of the portfolio is computed by multiplying all existing positions in the portfolio by estimated prices, reduced by a LIBOR-based time value of money adjustment and deduction of reserves for credit, price and market liquidity risks.
A key aspect of our operations and business strategy is our ability to provide customers with competitively priced bundled products and services that address their specific needs. Many of these customized products and services are not exchange-traded. In addition, the availability of reliable market quotations in certain regions and for certain commodities is limited as a result of liquidity and other factors. Consequently, we use a combination of market quotations, derivatives of market quotations and proprietary models to periodically value our portfolio as required by GAAP. Market quotations are validated against broker quotes, regulated exchanges or third-party information. Derivatives of market quotations use validated market quotes, such as actively traded power prices, as key inputs in determining market valuations.
In certain markets or for certain products, market quotes or derivatives of market quotes are not available or are not considered appropriate valuation techniques as a result of the newness of markets or products, a lack of
liquidity in such markets or products or other factors. However, under GAAP, estimating the value of these types of contracts is required. Consequently, prior to the third quarter 2001, we used models principally derived from market research to estimate forward price curves for valuing positions in these markets. Our models generated pricing estimates primarily for regional power markets in the United States and Europe. Price curves were derived by incorporating a number of factors, including broker quotes, near-term market indicators and a proprietary model based on a required rate of return on investment in new generation facilities. We believed that new generation needs in the United States and Europe primarily would be met through the construction of new gas-fired generation. Power prices, over the long term, would thus reflect the cost of building new gas fired generation, the cost of natural gas fuel and a cost of capital return on new construction investment.
Beginning in the third quarter 2001, we began to enter into longer-term power transactions in the United States with respect to which no broker quotes or other market data was available; consequently, we applied a proprietary model to estimate forward prices and, in turn, the fair market value of these longer-term power transactions.
During January 2003, in connection with the re-audit of our 1999-2001 financial statements and an assessment of various accounting policies, we reconsidered the model-based methodology we used to value the portions of our marketing and trading portfolio for which broker quotes were not available. After reconsidering the appropriateness of our former methodology in light of changing industry circumstances and in connection with the re-audit, in late January 2003, we determined that, beginning with the third quarter 2001, a different forward power curve methodology would more appropriately reflect the value of our long-term power contracts.
Upon making this determination, we corrected the forward power curve methodology we used to estimate the fair market value of our U.S. power marketing and trading portfolio. This corrected methodology incorporates forward energy prices derived from broker quotes and values from executed transactions to estimate forward price curves for periods where broker quotes and transaction data cannot be obtained. Further, we determined that in order to adequately reflect our results, it was appropriate to restate our prior period financial statements, beginning with the third quarter 2001, to reflect the corrected methodology. Please read Item 8, Financial Statements and Supplementary Data, Note 19-Quarterly Financial Information (Unaudited) beginning on page for further discussion.
Valuation of Tangible and Intangible Assets
We evaluate long-lived assets, such as property, plant and equipment, investments and goodwill, when events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows sufficient to indicate that the carrying value of such assets may not be recoverable. Factors we consider important, which could trigger an impairment include, among others:
•
significant underperformance relative to historical or projected future operating results;
•
significant changes in the manner of our use of the assets or the strategy for our overall business;
•
significant negative industry or economic trends; and
•
significant declines in stock value for a sustained period.
We assess the carrying value of our property, plant and equipment in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” If a long-lived asset is held and used, the determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. If an impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the fair value of the assets and recording a loss if the fair value was less than the book value. For assets identified as held for sale, the book value is compared to the estimated fair value to determine if an impairment loss is required.
We follow the guidance of APB 18, “The Equity Method of Accounting for Investments in Common Stock” and SFAS 115, “Accounting for Certain Investments in Debt and Equity Securities” when reviewing our investments. The book value of the investment is compared to the estimated fair value, based either on discounted cash flow projections or quoted market prices, if available, to determine if an impairment loss is required. We would record a loss when the decline in value is considered other than temporary. We follow the guidance set forth in SFAS No. 142, “Goodwill and Other Intangible Assets” when assessing the carrying value of our goodwill. Accordingly, we evaluate our goodwill for impairment on an annual basis, or when events warrant an assessment. Fair value utilized in this assessment is also based on our estimate of future cash flows.
Our assessment regarding the existence of impairment factors is based on market conditions, operational performance and legal factors of our businesses. Our review of factors present and the resulting estimation of the appropriate carrying value of our property, plant and equipment, investments and goodwill are subject to judgments and estimates that management is required to make. Our fair value estimates are impacted significantly by the estimated useful lives of the assets, commodity prices, regulations and discount rate assumptions.
Estimated Useful Lives
The estimated useful lives of our long-lived assets are used to compute depreciation expense and are also used for impairment testing. Estimated useful lives are based on the assumption that we provide an appropriate level of capital expenditures while the assets are still in operation. Without these continued capital expenditures, the useful lives of these assets could decrease significantly. These estimates could be impacted by future energy prices, environmental regulations and competition. If the useful lives of these assets were found to be shorter than originally estimated, depreciation charges would be accelerated.
Accounting for Contingencies
Environmental costs relating to current operations are expensed or capitalized, as appropriate, depending on whether such costs provide future economic benefit. Liabilities are recorded when environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Such liabilities may be recognized on a discounted basis if the amount and timing of anticipated expenditures for a site are fixed or reliably determinable; otherwise, such liabilities are recognized on an undiscounted basis. In assessing environmental liabilities, no offset is made for potential insurance recoveries. Recognition of any joint and several liability is based upon our best estimate of our final pro rata share of such liability. If our reserve balances were to either increase or decrease based on the factors mentioned above, the amount of the increase or decrease would be recognized immediately in earnings.
We are involved in numerous lawsuits, claims, proceedings and audits in the normal course of our operations. In accordance with SFAS No. 5, we record a loss contingency for these matters when it is probable that an asset has been impaired or a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss contingencies on an on-going basis to ensure they are adequately reserved on the balance sheet. These reserves are based on judgments made by management with respect to the likely outcome of these matters and are adjusted as appropriate. Our 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 judgments were applied to their matters it is likely that reserves would be recorded for different matters and in different amounts.
Accounting for Income Taxes
We follow the guidance in SFAS No. 109, “Accounting for Income Taxes,” which requires that we use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all
significant income tax temporary differences. Please read Item 8, Financial Statements and Supplementary Data, Note 12-Income Taxes beginning on page for further discussions.
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 exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within our consolidated balance sheet.
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 recovery is not likely, we must establish a valuation allowance. Significant management judgment is required in determining our provision for income taxes, our deferred tax assets and liabilities and any valuation allowance recorded against our deferred tax assets. To the extent we establish a valuation allowance or increase or decrease this allowance in a period, we must include an expense or benefit within the tax provisions in the statement of operations.
Accounting Pronouncements
See Item 8, Financial Statements and Supplementary Data, Note 2-Accounting Policies beginning on page, which is incorporated herein by reference, for a discussion of recently issued accounting pronouncements.
RISK-MANAGEMENT DISCLOSURES
The following table provides a reconciliation of the risk management data on our balance sheet, statement of operations and statement of cash flow (in millions).
(1)
This amount includes approximately ($12) million representing management’s estimate of the initial value of new contracts entered into during 2002.
(2)
This amount includes cash settlements of hedging instruments, emission allowances and other non-trading amounts in addition to the cash settlement of trading contracts.
(3)
Our modeling methodology was consistently applied during 2002.
(4)
This amount consists primarily of changes in value and cash settlements associated with foreign currency and interest rate hedges.
(5)
This amount consists primarily of changes in value of interest rate hedges.
(6)
This amount consists primarily of the customer and risk-management portion of WEN’s operating income before the deduction of Depreciation and Amortization, Impairment and Other Charges and General and Administrative Expenses.
(7)
This amount represents cash received for sales of emission credits and the settlement of fuel hedges and cash payments associated with foreign currency hedges.
(8)
This amount is calculated as “Cash received during the period” less “Net recognized operating income.”
(9)
The reduction in value of the portfolio from December 31, 2001 to December 31, 2002 is primarily due to the substantial liquidation of our European marketing portfolio and the accelerated settlement of our U.S. gas storage positions.
The net risk management asset of $358 million is the aggregate of the following line items on the Consolidated Balance Sheet: 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, 2002. 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
(1)
Mark-to-Market reflects the fair value of our risk-management asset position after deduction of time value, credit, price and other reserves necessary to determine fair value. These amounts exclude the fair value associated with certain derivative instruments designated as hedges.
(2)
Cash Flow reflects undiscounted cash inflows and outflows by contract based on tenor of individual contract position and has not been adjusted for counterparty credit or other reserves. These amounts exclude the cash flows associated with certain derivative instruments designated as hedges as well as other non-trading amounts.
The following table provides an assessment of net contract values by year based on our valuation methodology described above. Approximately 99 percent of our net risk-management asset value at December 31, 2002 was determined by market quotations or validation against industry posted prices.
Net Fair Value of Marketing Portfolio
(1)
Prices 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)
Mid-term prices validated against industry posted prices.
(3)
See “Critical Accounting Policies” beginning on page 59 for a discussion of our use of long-term models.
Derivative Contracts
The absolute notional contract amounts associated with our commodity risk-management, interest rate and foreign currency exchange contracts are discussed in Item 7A, Quantitative and Qualitative Disclosures about Market Risk beginning on page 67.
UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION
This Form 10-K includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements” under applicable SEC rules and regulations. 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,” “may,” “will,” “should,” “expect” and other words of similar meaning. In particular, these include, but are not limited to, statements relating to the following:
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Projected operating or financial results;
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Expectations regarding capital expenditures and other payments;
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Our beliefs and assumptions relating to our liquidity position, including our ability to satisfy or refinance our obligations as they come due;
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Our ability to execute additional capital-raising transactions or refinancings as necessary to enhance our liquidity position;
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Our ability to compete effectively for market share with industry participants;
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Beliefs about the outcome of legal and administrative proceedings, including matters involving the California power market, shareholder class action lawsuits against Dynegy Inc. and environmental matters as well as the investigations primarily relating to Project Alpha and our trading practices; and
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Our ability to manage our exit from third-party risk management aspects of the marketing and trading business and the timing of the expected cash flow realization and release of collateral related to this exit.
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 and uncertainties, including the following:
•
The timing and consummation of asset sales or other capital-raising activities;
•
The timing and extent of changes in commodity prices for energy, particularly natural gas, electricity and NGLs;
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The extent and timing of the entry of additional competition in our asset-based business lines;
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The condition of the capital markets generally, which will be affected by interest rates, foreign currency fluctuations and general economic conditions, and our financial condition, including our ability to satisfy our significant debt maturities and to maintain our credit ratings;
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Developments in the California power markets, including, but not limited to, governmental intervention, deterioration in the financial condition of our counterparties, default on receivables due and adverse results in current or future investigations or litigation;
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The effectiveness of our risk-management policies and procedures and the ability of our counterparties to satisfy their financial commitments;
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The liquidity and competitiveness of wholesale trading markets for energy commodities, particularly natural gas, electricity and NGLs;
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Operational factors affecting the start up or ongoing commercial operations of our power generation, natural gas and natural gas liquids facilities, including catastrophic weather-related damage, regulatory approvals, permit issues, unscheduled outages or repairs, unanticipated changes in fuel costs or availability of fuel emission credits, the unavailability of gas transportation, the unavailability of electric transmission service or workforce issues;
•
Increased interest expense and the other effects of our restructured credit facilities, including the security arrangements and restrictive covenants contained therein;
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The availability of trade credit and other factors affecting our financing activities, including the effect of our restatement of our 1999-2001 financial statements and the other issues described in this annual report;
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Our ability to generate sustainable earnings and cash flow from our assets and businesses;
•
The direct or indirect effects on our business of any further downgrades in our credit ratings (or actions we may take in response to changing credit ratings criteria), including refusal by counterparties to enter into transactions with us and our inability to obtain credit or capital in amounts or on terms that are considered favorable;
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Cost and other effects of legal and administrative proceedings, settlements, investigations and claims, including legal proceedings related to the California power market, shareholder claims against Dynegy Inc., claims arising out of the CRM business and environmental liabilities that may not be covered by indemnity or insurance, as well as the FERC, U.S. Attorney and other similar investigations primarily surrounding Project Alpha and our trading practices;
•
Other North American regulatory or legislative developments that affect the regulation of the electric utility industry, the demand for energy generally, increase the environmental compliance cost for our facilities or impose liabilities on the owners of such facilities; and
•
General political conditions and developments in the United States and in foreign countries whose affairs affect our lines of business, including any extended period of war or conflict.
Many of these factors will be important in determining our actual future results. Consequently, no forward-looking statement can be guaranteed. Our actual future results may vary materially from those expressed or implied in any forward-looking statements.
All of our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this annual report.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to commodity price variability related to our power generation and natural gas liquids businesses. In addition, fuel requirements at our power generation, gas processing and fractionation 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:
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manage and hedge our fixed-price purchase and sales commitments;
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reduce our exposure to the volatility of cash market prices; and
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hedge our fuel requirements for our generating facilities and natural gas processing plants.
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:
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Commodity price risks result from exposures to changes in spot prices, forward prices and volatilities in commodities, such as electricity, natural gas, NGLs and other similar products.
•
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.
•
Currency rate risks result from exposures to changes in spot prices, forward prices and volatilities in currency rates.
We seek 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.
Value at Risk (“VaR”)
In addition to applying business judgment, senior management uses a number of quantitative tools to monitor our exposure to market risk. These tools include:
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Risk limits based on a summary measure of market risk exposure, referred to as VaR; and
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Stress and scenario analyses performed daily that measure the potential effects of various market events, including substantial swings in volatility factors, absolute commodity price changes and the impact of interest rate movements.
The modeling of the risk characteristics of our mark-to-market portfolio, which includes power tolling arrangements, 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. 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 enterprise-wide marketing 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% 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% 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 one in one hundred 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. Average VaR is not available for 2002 and 2001 due to the restatement of historical results. While VaR can be calculated at a single point in time, it is not feasible to recalculate the historical results necessary to calculate an average.
The following table sets forth the aggregate daily VaR of our marketing portfolio (in millions):
DAILY AND AVERAGE VaR FOR MARKETING PORTFOLIO(1)
(1)
With respect to the power tolling arrangements included within our portfolio, amounts reflect the mark-to-market arrangements but do not include the accrual arrangements.
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 seek to enter into netting agreements with counterparties that permit us to offset receivables and payables with such counterparties. We attempt to further reduce credit risk with certain counterparties by obtaining third-party guarantees, entering into agreements that enable us to obtain collateral or terminating events of default.
Dynegy Inc.’s Credit Department, based on guidelines set by its Executive Risk Committee, establishes counterparty credit limits to the consolidated enterprise, including us. 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 further seek to measure credit exposure through the use of sensitivity analysis.
The following table represents our credit exposure, at December 31, 2002, associated with our forward positions within our risk management portfolio, netted by counterparty (in millions).
These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, in that the customer base may be similarly affected by changes in economic, industry, weather or other conditions.
Interest Rate Risk
Interest rate risk primarily results from variable rate debt obligations and changes in the value of our risk management portfolios, since changing interest rates impact the discounted value of future cash flows used to value risk-management assets and liabilities. Management continually monitors our exposure to fluctuations in interest rates and may execute swaps or other financial instruments to hedge and mitigate this exposure. As we continue to execute our restructuring strategy, our interest rate risk associated with providing risk-management services to customers will decline significantly.
Marketing portfolio. The following table sets forth the daily VaR associated with the interest rate component of the marketing portfolio. Average VaR is not available for 2002 and 2001 due to the restatement of historical results. While VaR can be calculated at a single point in time, it is not feasible to recalculate the historical results necessary to calculate an average. We seek to manage our interest rate exposure through application of various hedging strategies. Hedging instruments executed to mitigate such interest rate exposure in the marketing portfolio are included in the VaR as of December 31, 2002 and 2001 reflected in the table below.
Daily and Average Var On Interest Component of Marketing Portfolio
Variable Rate Financial Obligations. Based on sensitivity analysis as of December 31, 2002, it is estimated that a one percentage point interest rate movement in the average market interest rates (either higher or (lower)) in 2003 would decrease (increase) income before taxes by approximately $6.0 million. This amount was determined based on hypothetical interest rate movement on our variable rate financial obligations as of December 31, 2002.
Foreign Currency Exchange Rate Risk
Foreign currency risk arises from our investments in affiliates and subsidiaries owned and operated in foreign countries. Such risk is also a result of risk management transactions with customers in countries outside the United States Management continually monitors our exposure to fluctuations in foreign currency exchange rates. When possible, contracts are denominated in or indexed to the U.S. dollar, or such risk may be hedged through debt denominated in the foreign currency or through financial contracts.
At December 31, 2002, our primary foreign currency exchange rate exposures were the U.K. Pound, Canadian Dollar and European Euro. However, due to the sale of U.K. storage in 2002, DGC Europe in January 2003, as well as the winding down of the trading business in the U.K. and Canada through the first half of 2003, we expect our foreign currency exchange risk to decline significantly. We seek to manage our foreign currency exchange rate exposure through application of various hedging strategies.
The following table sets forth the daily and average Foreign Currency Exchange VaR (in millions):
Daily and Average Foreign Currency Exchange Var
The absolute notional contract amounts associated with the commodity risk-management, interest rate and foreign currency exchange contracts, respectively, were as follows:
ABSOLUTE NOTIONAL CONTRACT AMOUNTS
Item 8.
Item 8. Financial Statements and Supplementary Data
Our financial statements and financial statement schedule are set forth at pages through inclusive, found at the end of this Form 10-K, and are incorporated herein by reference.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Dynegy Inc.’s Board of Directors on March 15, 2002 dismissed Arthur Andersen LLP (“Arthur Andersen”) as the independent public accountants for the consolidated enterprise, including our company, and engaged PricewaterhouseCoopers LLP to serve as independent public accountants for the consolidated enterprise, including our company, for 2002.
Arthur Andersen’s reports on our consolidated financial statements for 2000 and 2001 did not contain an adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope or accounting principles.
During 2000 and 2001, there were no disagreements with Arthur Andersen on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures which, if not resolved to Arthur Andersen’s satisfaction, would have caused them to make reference to the subject matter in connection with their report on our consolidated financial statements for those years; and there were no reportable events, as listed in Item 304(a)(1)(v) of Regulation S-K.
We previously provided Arthur Andersen with a copy of the foregoing disclosures as such disclosures were set forth in a Form 8-K we filed on March 19, 2002. Attached to that Form 8-K as Exhibit 16 is a copy of Arthur Andersen’s letter, dated March 19, 2002, stating its agreement with such statements.
During 2000 and 2001 and through the date of Arthur Andersen’s dismissal, we did not consult PricewaterhouseCoopers LLP with respect to the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on our consolidated financial statements, or any other matters or reportable events listed in Items 304(a)(2)(i) and (ii) of Regulation S-K.
PART III
Item
10.
Item
10. Directors and Executive Officers of the Registrant
Omitted pursuant to General Instruction (I)(2)(c) of Form 10-K.
Item
11.
Item
11. Executive Compensation
Omitted pursuant to General Instruction (I)(2)(c) of Form 10-K.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Omitted pursuant to General Instruction (I)(2)(c) of Form 10-K.
Item 13.
Item 13. Certain Relationships and Related Transactions
Omitted pursuant to General Instruction (I)(2)(c) of Form 10-K.
PART IV
Item 14.
Item 14. Controls and Procedures
Within the 90-day period immediately preceding the filing of this Form 10-K, an evaluation was carried out under the supervision and with the participation of our management and the management of Dynegy Inc., including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of the consolidated enterprise’s disclosure controls and procedures (as defined in Rule 13a-14(c) under the Exchange Act). This evaluation included consideration of the establishment of a disclosure committee and the various processes that were carried out under the direction of this committee in an effort to ensure that information required to be disclosed in the consolidated enterprise’s SEC reports, including ours, is recorded, processed, summarized and reported within the time periods specified by the SEC. This evaluation also included consideration of the consolidated enterprise’s internal controls and procedures for the preparation of consolidated financial statements. While internal control weaknesses were identified, which are discussed below, this evaluation indicated that these weaknesses did not impair the effectiveness of the overall disclosure controls and procedures applied throughout the enterprise.
In evaluating these internal controls we sought to determine whether there were any “significant deficiencies” and in particular whether there were any “material weaknesses.” Under the applicable accounting literature, “significant deficiencies” are referred to as “reportable conditions,” which are control issues that could have a significant adverse effect on our ability to record, process, summarize and report financial data in the financial statements. A “material weakness” is defined as a particularly serious reportable condition where the internal control does not reduce to a relatively low level the risk that (a) misstatements caused by the error may occur in amounts that would be material in relation to the financial statements and (b) that such misstatements would not be detected timely by employees in the normal course of performing their assigned functions.
Our management, which also serve as management for Dynegy Inc., and the Dynegy Inc. Audit Committee are aware of two reportable conditions relating to our operations, both of which were considered to be “material weaknesses” for the year ended December 31, 2002 under standards established by the American Institute of Certified Public Accountants. The first such condition related to the fact that inappropriate persons within our organization had access to record or revise entries in our accounting software system. We have taken action to test whether this access resulted in any inappropriate entries being recorded or revised and concluded that no such activities occurred. We are currently developing a technical solution to ensure that access to our accounting
software system is limited to appropriate personnel, and we expect to implement this solution in the near term. In the interim, we have strengthened our monitoring policy with respect to the entries that are recorded or revised in this system to validate that all such entries are recorded or revised by appropriate personnel. The second such condition related to the process whereby accrued estimates of volumes bought, sold, transported and stored in our natural gas marketing business were reconciled to the actual volumes. In July 2002, in response to the identification of this condition, we adopted additional procedures identifying and implementing specified key controls designed to improve the quality of our monthly monitoring and reconciliation process. A reconciliation has been completed and corrections resulting from this process are reflected in the audited consolidated financial statements included in this report.
Additionally, we are undergoing a major organizational restructuring in connection with, among other things, our exit from third-party marketing and trading. We also have experienced significant changes in senior management and other accounting personnel over the past year. Our new management team is operating in an atmosphere of historic legislative, regulatory and accounting reform with respect to which there have been many new laws, regulations and accounting pronouncements that are expected to affect the business environment for years to come. In response to this new environment, Dynegy Inc. has undertaken a number of initiatives, including the following:
•
engagement of a new Vice President of Internal Audit; and
•
engagement of external consultants to assist in a review of the consolidated enterprise’s internal control processes and procedures.
As part of this effort, a strategy for formalizing the consolidated enterprise’s internal controls and procedures for financial reporting is being developed in accordance with the SEC’s proposed rules to implement the internal control report requirements included in Section 404 of the Sarbanes-Oxley Act. It is possible that additional changes will be made to our internal controls as a result of these efforts.
Item
15.
Item
15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) The following documents, which we have filed with the SEC pursuant to the Securities Exchange Act of 1934, as amended, are by this reference incorporated in and made a part of this annual report:
1. Financial Statements - Our consolidated financial statements are incorporated under Item 8. of this annual report.
2. Financial Statement Schedules - Financial Statement Schedules are incorporated under Item 8. of this annual report.
3. Exhibits - The following instruments and documents are included as exhibits to this annual report. All management contracts or compensation plans or arrangements set forth in such list are marked with a .
Exhibit
Number
Description
3.1
-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. 0-29311).
3.2
-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. 0-29311).
4.1
-Indenture, dated as of December 11, 1995, by and among NGC Corporation, the Subsidiary Guarantors named therein and the First National Bank of Chicago, as Trustee (incorporated by reference to exhibits to the Registration Statement on Form S-3 of NGC Corporation, Registration No. 33-97368).
Exhibit
Number
Description
4.2
-First Supplemental Indenture, dated as of August 31, 1996, by and among NGC Corporation, the Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.4 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1996 of NGC Corporation, File No. 1-11156).
4.3
-Second Supplemental Indenture, dated as of October 11, 1996, by and among NGC Corporation, the Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1996 of NGC Corporation, File No. 1-11156).
4.4
-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).
4.5
-Amended and Restated Declaration of Trust among NGC Corporation, Wilmington Trust Company, as Property Trustee and Delaware Trustee, and the Administrative Trustees named therein, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.6 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).
4.6
-Series A Capital Securities Guarantee 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).
4.7
-Common Securities Guarantee 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).
4.8
-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).
4.9
-Fourth Supplemental Indenture among NGC Corporation, Destec Energy, Inc. and The First National Bank of Chicago, as Trustee, dated as of June 30, 1997, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.12 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1997 of NGC Corporation, File No. 1-11156).
4.10
-Fifth Supplemental Indenture among NGC Corporation, The Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, dated as of September 30, 1997, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.18 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1997 of NGC Corporation, File No. 1-11156).
4.11
-Sixth Supplemental Indenture among NGC Corporation, The Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, dated as of January 5, 1998, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.19 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1997 of NGC Corporation, File No. 1-11156).
Exhibit
Number
Description
4.12
-Seventh Supplemental Indenture among NGC Corporation, The Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, dated as of February 20, 1998, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.20 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1997 of NGC Corporation, File No. 1-11156).
4.13
-Indenture, dated as of September 26, 1996, restated as of March 23, 1998, and amended and restated as of March 14, 2001, between Dynegy Holdings Inc. and Bank One Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.17 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2000 of Dynegy Holdings Inc., File No. 0-29311).
There have not been filed or incorporated as exhibits to this annual report, other debt instruments defining the rights of holders of our long-term debt, none of which relates to authorized indebtedness that exceeds 10% of our consolidated assets. We hereby agree to furnish a copy of any such instrument not previously filed to the SEC upon request.
10.1
-Dynegy Inc. Amended and Restated 1991 Stock Option Plan (incorporated by reference to Exhibit 10.3 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156). 
10.2
-Dynegy Inc. 1998 U.K. Stock Option Plan (incorporated by reference to Exhibit 10.4 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156). 
10.3
-Dynegy Inc. Amended and Restated Employee Equity Option Plan (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156). 
10.4
-Dynegy Inc. 1999 Long Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156). 
10.5
-Dynegy Inc. 2000 Long Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156). 
10.6
-Dynegy Inc. 2001 Non-Executive Stock Incentive Plan (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76080). 
10.7
-Dynegy Inc. 2002 Long Term Incentive Plan (incorporated by reference to Appendix A to the Definitive Proxy Statement on Schedule 14A of Dynegy Inc., File No. 1-15659, filed with the SEC on April 9, 2002). 
10.8
-Employment Agreement, effective October 23, 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). 
10.9
-Employment Agreement, effective February 1, 2000, between Charles L. Watson and Dynegy Inc. (incorporated by reference to Exhibit 10.9 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156)
10.10
-Employment Agreement, effective February 1, 2000, between Stephen W. Bergstrom and Dynegy Inc. (incorporated by reference to Exhibit 10.10 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156).
10.11
-Employment Agreement, effective September 16, 2002, between R. Blake Young and Dynegy Inc. (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2002 of Dynegy Inc., File No. 1-15659).
Exhibit
Number
Description
10.12
-Employment Agreement, effective February 1, 2000, between Kenneth E. Randolph and Dynegy Inc. (incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No 1-11156).
10.13
-Employment Agreement, effective February 1, 2000, between Matthew K. Schatzman and Dynegy Inc. (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2000 of Dynegy Inc., File No. 1-15659).
10.14
-Employment Agreement, effective February 1, 2000, between Alec G. Dreyer and Dynegy Inc. (incorporated by reference to Exhibit 10.15 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2002 of Dynegy Inc., File No. 1-15659).
10.15
-Employment Agreement, effective December 2, 2002, between Nick J. Caruso and Dynegy Inc. (incorporated by reference to Exhibit 10.16 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2002 of Dynegy Inc., File No. 1-15659).
10.16
-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 March 31, 2000 of Dynegy Inc., File No. 1-15659). 
10.17
-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. 333-76570). 
10.18
-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). 
10.19
-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). 
10.20
-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). 
10.21
-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 Fiscal Year Ended December 31, 2001 of Dynegy Inc., File No. 1-15659). 
10.22
-Lease Agreement entered into on June 12, 1996 between Metropolitan Life Insurance Company and Metropolitan Tower Realty Company, Inc., as landlord, and NGC Corporation, as tenant (incorporated by reference to exhibits to the Registration Statement on Form S-4 of Midstream Combination Corp., Registration No. 333-09419).
10.23
- First Amendment to Lease Agreement entered into on June 12, 1996 between Metropolitan Life Insurance Company and Metropolitan Tower Realty Company, Inc., as landlord, and NGC Corporation, as tenant (incorporated by reference to exhibits to the Registration Statement on Form S-4 of Midstream Combination Corp., Registration No. 333-09419).
*10.24
-Master Natural Gas Liquids Purchase Agreement, dated as of September 1, 1996, between Warren Petroleum Company, Limited Partnership and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1996 of NGC Corporation, File No. 1-11156).
10.25
-Shareholder Agreement of Energy Convergence Holding Company with Chevron U.S.A. Inc. (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K of Dynegy Inc., File No. 1-11156, dated June 14, 1999).
10.26
-Dynegy Inc. Severance Pay Plan (incorporated by reference to Exhibit 10.41 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156). 

Filed herewith
*
Exhibit omits certain information that has been filed separately with the SEC pursuant to a confidential treatment request pursuant to Rule 406 promulgated under the Securities Act of 1933, as amended.
**
Furnished herewith
(b)
Reports on Form 8-K of Dynegy Holdings Inc. for the fourth quarter of 2002.
1. During the quarter ended December 31, 2002, we filed a Current Report on Form 8-K on October 2, 2002. Items 5 and 7 were reported and no financial statements were filed.
2. During the quarter ended December 31, 2002, we filed a Current Report on Form 8-K on October 22, 2002. Items 5, 7 and 9 were reported and no financial statements were filed.
3. During the quarter ended December 31, 2002, we filed a Current Report on Form 8-K on October 23, 2002. Items 5 and 7 were reported and no financial statements were filed.
4. During the quarter ended December 31, 2002, we filed a Current Report on Form 8-K on November 19, 2002. Items 5 and 7 were reported and no financial statements were filed.
5. During the quarter ended December 31, 2002, we filed a Current Report on Form 8-K on December 3, 2002. Items 5 and 7 were reported and no financial statements were filed.
6. During the quarter ended December 31, 2002, we filed a Current Report on Form 8-K on December 23, 2002. Items 5 and 7 were reported and no financial statements were filed.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.
/s/ BRUCE A. WILLIAMSON
Bruce A. Williamson
President, Chief Executive Officer and Director (Principal Executive Officer)
April 15, 2003
/s/ NICK J. CARUSO
Nick J. Caruso
Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer)
April 15, 2003
/s/ HOLLI C. NICHOLS
Holli C. Nichols
Senior Vice President and Controller (Principal Accounting Officer)
April 15, 2003
/s/ CAROL F. GRAEBNER
Carol F. Graebner
Director
April 15, 2003
SECTION 302 CERTIFICATION
I, Bruce A. Williamson, certify that:
1. I have reviewed this 2002 Annual Report on Form 10-K (“10-K”) of Dynegy Holdings Inc. (“Dynegy”);
2. Based on my knowledge, this 10-K does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this 10-K;
3. Based on my knowledge, the financial statements, and other financial information included in this 10-K fairly present in all material respects the financial condition, results of operations and cash flows of Dynegy as of, and for, the periods presented in this 10-K;
4. Dynegy’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for Dynegy and have:
(a) designed such disclosure controls and procedures to ensure that material information relating to Dynegy, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
(b) evaluated the effectiveness of Dynegy’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
(c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. Dynegy’s other certifying officer and I have disclosed, based on our most recent evaluation, to Dynegy’s auditors and the audit committee of Dynegy’s board of directors (or persons performing the equivalent functions):
(a) all significant deficiencies in the design or operation of internal controls which could adversely affect Dynegy’s ability to record, process, summarize and report financial data and have identified for Dynegy’s auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or other employees who have a significant role in Dynegy’s internal controls; and
6. Dynegy’s other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: April 15, 2003
/s/ BRUCE A. WILLIAMSON
Bruce A. Williamson
President and Chief Executive Officer
SECTION 302 CERTIFICATION
I, Nick J. Caruso, certify that:
1. I have reviewed this 2002 Annual Report on Form 10-K (“10-K”) of Dynegy Holdings Inc. (“Dynegy”);
2.
Based on my knowledge, this 10-K does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this 10-K;
3. Based
on my knowledge, the financial statements, and other financial information included in this 10-K fairly present in all material respects the financial condition, results of operations and cash flows of Dynegy as of, and for, the periods presented in this 10-K;
4.
Dynegy’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for Dynegy and have:
(a)
designed such disclosure controls and procedures to ensure that material information relating to Dynegy, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
(b)
evaluated the effectiveness of Dynegy’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
(c)
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.
Dynegy’s other certifying officer and I have disclosed, based on our most recent evaluation, to Dynegy’s auditors and the audit committee of Dynegy’s board of directors (or persons performing the equivalent functions):
(a)
all significant deficiencies in the design or operation of internal controls which could adversely affect Dynegy’s ability to record, process, summarize and report financial data and have identified for Dynegy’s auditors any material weaknesses in internal controls; and
(b) any
fraud, whether or not material, that involves management or other employees who have a significant role in Dynegy’s internal controls; and
6.
Dynegy’s other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: April 15, 2003
/s/ NICK J. CARUSO
Nick J. Caruso
Executive Vice President and
Chief Financial Officer
DYNEGY HOLDINGS INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Consolidated Financial Statements
Report of Independent Accountants
Consolidated Balance Sheets as of December 31, 2002 and 2001
Consolidated Statements of Operations for the years ended December 31, 2002, 2001 and
Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and
Consolidated Statements of Changes in Stockholder’s Equity for the years ended December 31, 2002, 2001 and 2000
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2002, 2001 and 2000
Notes to Consolidated Financial Statements
Financial Statement Schedule
Valuation and Qualifying Accounts
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholder of Dynegy Holdings Inc.:
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Dynegy Holdings Inc. and its subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index 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 this financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and this financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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 14, the Company is the subject of substantial litigation. The Company’s ongoing liquidity, financial position and operating results may be adversely impacted by the nature, timing and amount of the resolution of such litigation. The consolidated financial statements do not include any adjustments, beyond existing accruals applicable under Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies,” that might result from the ultimate resolution of such matters.
As discussed in Note 2, the Company adopted the provisions of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” and Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” As discussed in Note 2, the Company adopted certain provisions of Emerging Issues Task Force No. 02-03, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” As discussed in Note 5, the Company adopted the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” as of January 1, 2001.
PricewaterhouseCoopers LLP
Houston, Texas
April 9, 2003
DYNEGY HOLDINGS INC.
CONSOLIDATED BALANCE SHEETS
(in millions)
See Notes to Consolidated Financial Statements.
DYNEGY HOLDINGS INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
See Notes to Consolidated Financial Statements.
DYNEGY HOLDINGS INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
See Notes to Consolidated Financial Statements.
DYNEGY HOLDINGS INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY
(in millions)
See Notes to Consolidated Financial Statements.
DYNEGY HOLDINGS INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in millions)
See Notes to Consolidated Financial Statements
DYNEGY HOLDINGS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EXPLANATORY NOTE-RESTATEMENTS
Concurrent with the filing of this Form 10-K , we are filing with the SEC Amendment No. 1 to our Annual Report on Form 10-K for the year ended December 31, 2001 (“Amendment No. 1”). This Amendment No. 1 contains restatements of our financial statements for each of the three years in the period ended December 31, 2001. Those restated financial statements, which have been audited by PricewaterhouseCoopers LLP, contain adjustments to the financial statements originally included in our Annual Report on Form 10-K for the year ended December 31, 2001 as filed on March 22, 2002. The restated financial information contained in this Form 10-K is consistent with the restated information set forth in Amendment No. 1.
As previously disclosed, PricewaterhouseCoopers LLP did not review our 2002 quarterly financial statements when we included such statements in our 2002 Quarterly Reports on Form 10-Q, pending the completion of their three-year re-audit. Please read Note 19-Quarterly Financial Information (Unaudited), beginning on page, for a discussion of our 2002 quarterly financial statements, which reflect restatements of the financial statements included in our 2002 quarterly reports as originally filed.
NOTE 1-ORGANIZATION AND OPERATIONS OF THE COMPANY
Dynegy Holdings Inc. (together with our subsidiaries, “we,” “us” or “our”) is a holding company and conducts substantially all of its business through its subsidiaries. We own operating divisions engaged in power generation and natural gas liquids. Through these business units, we serve customers by delivering value-added solutions to meet their energy needs. We had three reportable business segments in 2002: Wholesale Energy Network (“WEN”), Dynegy Midstream Services (“DMS”) and Transmission and Distribution (“T&D”). Our operating segments for 2003 will include Power Generation, Natural Gas Liquids and Customer Risk Management. We determined to report our results in these two business segments based on the diversity of their respective operations.
We are a wholly owned subsidiary of Dynegy Inc. Dynegy Inc. acquired Illinova Corporation (“Illinova”) in the first quarter of 2000. As part of the acquisition of Illinova, the former Dynegy Inc., which was renamed Dynegy Holdings Inc., became a wholly owned subsidiary of a new holding company, Dynegy Inc. The assets, liabilities and operations of the former Dynegy Inc. before the acquisition became the assets, liabilities and operations of Dynegy Holdings Inc. after the acquisition.
At the end of September 2000, Dynegy Inc. contributed Dynegy Midwest Generation (“DMG”) to us. DMG owns and operates the fossil fuel generating assets formerly held by Illinois Power Company (“IP”), a wholly owned subsidiary of Illinova. The net contribution of approximately $2.2 billion was accounted for in a manner similar to a pooling of interests. As a result, DMG’s results of operations are reflected in our results of operations for all of 2000 and thereafter.
NOTE 2-ACCOUNTING POLICIES
Our accounting policies conform to generally accepted accounting principles in the United States of America (“GAAP”). Our more significant accounting policies are described below. The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to develop estimates and to make assumptions that affect reported financial position and results of operation which impact the nature and extent of disclosure, if any, of contingent assets and liabilities. We review significant estimates affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Judgments and estimates are based on our beliefs and assumptions derived from information available at the time such adjustments are made. Adjustments made with
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
respect to the use of these estimates often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates are primarily used in (1) developing fair value assumptions, including estimates of future cash flows and discounts rates, (2) analyzing tangible and intangible assets for impairment, (3) estimating the useful lives of our assets, (4) assessing future tax exposure and the realization of tax assets, (5) determining the amounts to accrue related to contingencies and (6) the estimate of various factors impacting the valuation of our pension assets. Actual results could differ materially from any such estimates.
Principles of Consolidation. The accompanying consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries, and our proportionate share of assets, liabilities, revenues and expenses of undivided interests in certain gas processing facilities, after elimination of intercompany accounts and transactions. Certain reclassifications have been made to prior-period amounts to conform with current-period financial statement classifications.
Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.
Allowance for Doubtful Accounts. We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance. We review collectibility and establish or adjust our allowance as necessary using the specific identification method.
Investment in Unconsolidated Affiliates. Investments in affiliates in which we have a significant ownership interest, generally 20 percent to 50 percent, are accounted for by the equity method. Prior to our adoption on January 1, 2002 of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (“Statement No. 142”), any excess of our investment in affiliates was amortized over the estimated economic service lives of the underlying assets. Other investments less than 20 percent owned with readily determinable fair value are considered available-for-sale and are recorded at quoted market value or at the lower of cost or net realizable value, if there is no readily determinable fair value. For securities with a readily determinable fair value, 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. These investments are periodically assessed for other-than-temporary declines in value, with related charges recognized within earnings (losses) of unconsolidated investments in the consolidated statements of operations.
Concentration of Credit Risk. We provide multiple energy commodity solutions principally to customers in the electric and 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, in that the customer base may be similarly affected by changes in economic, industry, weather or other conditions.
Inventories. Inventories consisted primarily of NGLs of $46 million and $49 million, coal of $49 million and $62 million and crude oil of $10 million and $19 million at December 31, 2002 and 2001 and natural gas in storage of $9 million at December 31, 2001. Such inventory is valued at the lower of weighted average cost or at market. Materials and supplies inventory of $79 million and $62 million at December 31, 2002 and 2001, respectively, is carried at the lower of cost or market using the specific identification method.
Property, Plant and Equipment. Property, plant and equipment, which consists principally of gas gathering, processing, fractionation, terminaling and storage facilities, natural gas transmission lines, pipelines
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
and power generating facilities is recorded at historical cost. Expenditures for major replacements, renewals, and major maintenance are capitalized. We consider major maintenance to be expenditures incurred on a cyclical basis in order to maintain and prolong the efficient operation of our assets. Expenditures for repairs and minor renewals to maintain facilities in operating condition are expensed. Depreciation is provided using the straight-line method over the estimated economic service lives of the assets, ranging from three to 40 years. Composite depreciation rates are applied to functional groups of property having similar economic characteristics. The estimated economic service lives are as follows:
Gains and losses are not recognized for retirements of property, plant and equipment subject to composite depreciation rates (“composite rate”) until the asset group subject to the composite rate is retired. Gains and losses on the sale of individual assets are reflected in loss (gain) on asset sales in the consolidated statements of operations. Through December 31, 2001, we reviewed the carrying value of our long-lived assets in accordance with provisions of Statement of Financial Accounting Standards No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed of” (“Statement No. 121”). In August 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“Statement No. 144”). Statement No. 144 addresses the accounting and reporting for the impairment or disposal of long-lived assets and supersedes Statement No. 121 and APB Opinion No. 30, “Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.” Under this standard, we evaluate an asset for impairment when events or circumstances indicate that a long-lived asset’s carrying value may not be recovered. These events include market declines, changes in the manner in which we intend to use an asset or decisions to sell an asset and adverse changes in the legal or business environment. When we decide to exit or sell a long-lived asset or group of assets, we adjust the carrying value of these assets downward, if necessary, to the estimated sales price, less costs to sell. Our adoption of Statement No. 144 on January 1, 2002 did not have any impact on our financial position or results of operations. See Note 4-Restructuring and Impairment Charges, beginning on page, for a discussion of impairment charges we recognized in 2002.
Other Contingencies. Environmental costs relating to current operations are expensed or capitalized, as appropriate, depending on whether such costs provide future economic benefit. Liabilities are recorded when environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based on currently enacted laws and regulations, existing technology and site-specific costs. Such liabilities may be recognized on a discounted basis if the amount and timing of anticipated expenditures for a site are fixed or reliably determinable; otherwise, such liabilities are recognized on an undiscounted basis. Environmental liabilities incurred by providing indemnification in connection with assets that are sold or closed are recognized upon such sale or closure, to the extent they are probable, can be estimated and have not previously been reserved. In assessing environmental liabilities, no offset is made for potential insurance recoveries. Recognition of any joint and several liability is based upon our best estimate of our final pro rata share of such liability.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“Statement No. 143”). We adopted this Statement effective January 1, 2003. Statement No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets. Under Statement No. 143, the asset retirement obligation is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the related asset. Upon adoption, the cumulative effect of applying Statement No. 143 will be recognized as a change in accounting principle in the consolidated statements of operations.
As part of the transition adjustment in adopting Statement No. 143, certain existing environmental liabilities are required to be reversed upon adoption of Statement No 143. As we had previously accrued environmental liabilities of approximately $73 million for which remediation can be delayed until asset retirement, such liabilities have been reversed as a component of the cumulative effect adjustment in adopting Statement No. 143. As such, we expect the impact of adopting Statement No. 143 will be an increase in earnings, net of tax, of approximately $33 million, to be reflected as a cumulative effect of a change in accounting principle in the first quarter 2003. The annual amortization of the asset created under this standard and the accretion of the liability to its fair value is estimated to be approximately $6 million in 2003. We also have asset retirement obligations which are not quantifiable given our inability to estimate in a reasonable manner the time of settlement. At the time we are able to estimate the timing of the asset retirement obligation, a liability will be established.
Liabilities for other contingencies are recognized in accordance with Statement No. 5 upon identification of an exposure, which when fully analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that such loss amount can be reasonably estimated. Non-capital costs to remedy such contingencies or other exposures are charged to a reserve, if one exists, or otherwise to current-period operations. When a range of probable loss exists, we accrue the lesser end of the range.
Goodwill and Other Intangible Assets. Prior to January 1, 2002, intangible assets, principally goodwill, were amortized on a straight-line basis over their estimated useful lives of 25 to 40 years. However, effective January 1, 2002, we adopted Statement No. 142, and, accordingly, we discontinued amortizing goodwill. In accordance with Statement No. 142, we subject goodwill to a fair value-based impairment test on at least an annual basis. As further discussed in Note 9-Goodwill beginning on page, the adoption of Statement No. 142 and the resulting impairment test caused us to recognize an impairment of $724 million in 2002 related to the WEN segment. 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. Accordingly, if conditions change in the future, we may record further impairment losses on an annual basis, absent any specific impairment indicators. We expect to perform our annual impairment test in the fourth quarter after the annual budgetary process.
Revenue Recognition. We utilize two comprehensive accounting models in reporting our consolidated financial position and results of operations as required by generally accepted accounting principles - an accrual model and a fair value model. We determine the appropriateness of application of one comprehensive accounting model over the other in accounting for our varied operations based on guidance provided in numerous accounting standards and positions adopted by the FASB or the SEC.
The accrual model has historically been used to account for substantially all of the operations conducted in the DMS and T&D segments as well as all physically operated assets owned by the WEN segment. Ownership and operation of physical assets characterize these businesses. We use these physical assets in various generation, processing and delivery operations. These operations include the generation of electricity, the separation of natural gas liquids into their
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
component parts from a stream of natural gas and the transportation or transmission of commodities through pipelines. End sales from these businesses result in physical delivery of commodities or services to our wholesale and commercial and industrial customers.
Revenues for product sales and gas processing and marketing services are recognized when title passes to the customer or when the service is performed. Fractionation and transportation revenues are recognized based on volumes received in accordance with contractual terms. Revenues derived from power generation are recognized upon output, product delivery or satisfaction of specific targets, all as specified by contractual terms. Shipping and handling costs are included in revenue when billed to customers in conjunction with the sale of products.
The fair value model is used to account for certain forward physical and financial transactions in the WEN and DMS segments, which meet criteria defined by the FASB or the Emerging Issues Task Force (“EITF”). These criteria require these contracts to be related to future periods, to contain fixed price and volume components and to have terms that require or permit net settlement of the contract in cash or its equivalent. As these transactions may be settled in cash, the value of the assets and liabilities associated with these transactions is reported at estimated settlement value based on current prices and rates as of each balance sheet date. The net gains or losses resulting from the revaluation of these contracts during the period are recognized currently in our results of operations. Assets and liabilities associated with these transactions are reflected on our balance sheet as risk-management assets and liabilities, classified as short-term (i.e., current) or long-term pursuant to each contract’s individual length.
We estimate the fair value of our marketing portfolio using a liquidation value approach assuming that our ability to transact business in the market remains at historical levels. The estimated fair value of our portfolio is computed by multiplying all existing positions in our portfolio by estimated prices, reduced by a LIBOR-based time value of money adjustment and deduction of reserves for credit, price and market liquidity risks.
A key aspect of our historical operations and business strategy has been our ability to provide customers with competitively priced bundled products and services that address customer specific energy and risk management needs. Many of these customized products and services are not exchange-traded. In addition, the availability of reliable market quotations in certain regions and for certain commodities is limited as a result of liquidity and other factors. We use a combination of market quotations, derivatives of market quotations and proprietary models to periodically value our portfolio as required by generally accepted accounting principles. Market quotations are validated against broker quotes, regulated exchanges or third-party information. Derivatives of market quotations use validated market quotes, such as actively traded natural gas or power prices, as key inputs in determining market valuations.
In certain markets or for certain products, market quotes or derivatives of market quotes are not available or are not considered appropriate valuation techniques as a result of the newness of markets or products, a lack of liquidity in such markets or products or other factors. However, under generally accepted accounting principles, estimating the value of these types of contracts is required. Consequently, prior to the third quarter 2001, we used models principally derived from market research to estimate forward price curves for valuing positions in these markets. Our models generated pricing estimates primarily for regional power markets in the United States and Europe. Price curves were derived by incorporating a number of factors, including broker quotes, near-term market indicators and a proprietary model based on a required rate of return on investment in new generation facilities. Power prices under this model, over the long term, would thus reflect the cost of building new gas fired generation, the cost of natural gas fuel and a cost of capital return on new construction investment.
During January 2003, in connection with the re-audit of our 1999-2001 financial statements and an assessment of various accounting policies, we reconsidered the model-based methodology utilized to estimate
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forward power curves based on the increasing term length of contractual arrangements within our U.S. power portfolio in the third quarter 2001. Based on this assessment, we corrected our methodology utilized to estimate forward U.S. power curves effective for the third quarter 2001. The corrected power curve methodology incorporates forward energy prices derived from broker quotes and values from executed transactions to develop mathematical forward price curves for periods where broker quotes and transaction data cannot be obtained. While we believe our corrected pricing model is based on reasonable and sound assumptions, the application of forecasted pricing curves to contractual commitments may result in realized cash return on these commitments that vary significantly, either positively or negatively, from the estimated values. Please read Note 19-Quarterly Financial Information (Unaudited) beginning on page for further discussion.
During 2002, the EITF reached several consensuses regarding Issue 02-03, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue 02-03”). First, all mark-to-market gains and losses on energy trading contracts, whether realized or unrealized, are required to be shown net in the income statement, irrespective of whether the contract is physically or financially settled. We had historically classified net unrealized gains and losses from energy trading contracts as revenue in our consolidated statements of operations. Physical transactions that were realized and settled were previously reflected gross in revenues and costs of sales. This change in accounting classification has no impact on operating income, net income, earning per share or cash flow from operations. In accordance with the transition provisions in the consensus, comparative period financial statements have been conformed to reflect this change in accounting principle.
The following table reconciles the revenues and costs of sales as previously reported to the amounts reported herein ($ in millions):
Second, in October 2002, the EITF reached a consensus to rescind EITF Issue 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (“EITF 98-10”), which was the guidance requiring us to use mark-to-market accounting for our energy trading contracts. While the rescission of EITF 98-10 will reduce the number of contracts accounted for on a mark-to-market basis, it does not eliminate mark-to-market accounting. All derivative contracts that either do not qualify, or are not designated, as hedges will continue to be marked-to-market in accordance with Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“Statement No. 133”). Any earnings/losses previously recognized under EITF 98-10 that would not have been recognized under Statement No. 133 will be reversed in the first quarter 2003 as a cumulative effect of a change in accounting principle. The first quarter pre-tax income is expected to be approximately $35 million, primarily reflecting losses previously recognized prior to the settlement of power tolling arrangements offset by the reversal of mark-to-market earnings previously recognized prior to the settlement of natural gas storage contracts, transportation contracts and retail power sales.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
A third issue addressed by the EITF in EITF Issue 02-03 deals with the recognition of unrealized gains and losses at inception of an energy trading contract (commonly referred to as dealer profit). The EITF did not reach a consensus on this issue.
We have historically entered into financial instrument contracts to hedge purchase and sale commitments, fuel requirements and inventories in our NGL, electricity and coal businesses in order to minimize the risk of changes in market prices in these commodities. We also monitor our exposure to fluctuations in interest rates and foreign currency exchange rates and may execute swaps, forward-exchange contracts or other financial instruments to manage these exposures. Gains and losses from hedging transactions are recognized in income in the periods for which the underlying commodity, interest rate or foreign currency transaction impacts earnings in the same line item as the underlying transaction on the consolidated statements of operations. If the underlying contract being hedged by the commodity, interest rate or foreign currency transaction is disposed of or otherwise terminated, the gain or loss associated with such contract is no longer deferred and is recognized in the period the underlying contract is eliminated. If the hedging transaction is terminated prior to the occurrence of the underlying transaction being hedged, the gain or loss associated with the hedging transaction is deferred and recognized in income in the period in which the underlying transaction being hedged occurs.
Cash inflows and outflows associated with the settlement of risk management activities are recognized in operating cash flows.
Income Taxes. Our parent, Dynegy Inc., files a consolidated United States federal income tax return and, for financial reporting purposes, provides income taxes for the difference in the tax and financial reporting bases of our assets and liabilities in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes.”
We are included in the consolidated federal and state income tax returns filed by Dynegy Inc. Pursuant to tax allocation arrangements, we record a receivable in an amount equal to the tax benefits realized in Dynegy Inc.’s consolidated federal income tax return resulting from the utilization of our net operating losses and/or tax credits, or record a payable to Dynegy Inc. an amount equal to the federal income tax computed on our separate company taxable income less the tax benefits associated with net operating losses and/or tax credits generated by us which are utilized in Dynegy Inc.’s consolidated federal income tax return.
Foreign Currency Translations. For subsidiaries whose functional currency is not the U.S. Dollar, assets and liabilities are translated at year-end rates of exchange and revenues and expenses are translated at monthly average exchange rates. Translation adjustments for the asset and liability accounts are included as a separate component of accumulated other comprehensive loss in stockholder’s equity. Currency transaction gains and losses are recorded in income and totaled gains of $13 million, losses of $10 million and gains of $36 million for the years ended December 31, 2002, 2001 and 2000, respectively.
Employee Stock Options. We currently apply the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”) and related interpretations in accounting for Dynegy Inc.’s issuance of stock options to our employees. Accordingly, compensation expense is not recognized for employee stock options unless the options were granted at an exercise price lower than the market value on the grant date. Dynegy Inc. has granted in-the-money options in the past and continues to recognize compensation expense over the applicable vesting periods. Since 2001, no in-the-money stock options have been issued.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Had compensation cost been determined on a fair value basis consistent with Statement No. 123, our net income and per share amounts would have approximated the following pro forma amounts for the years ended December 31, 2002, 2001 and 2000, respectively:
The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions used for grants in 2002, 2001 and 2000: dividends per year of $0.15 for 2002 and $0.30 per share for 2001 and 2000; expected volatility of 74.3 percent, 46.4 percent and 42.1 percent, respectively; a risk-free interest rate of 4.2 percent, 4.3 percent and 6.1 percent, respectively; and an expected option life of ten years for all periods. As stated previously, we account for our stock option plan in accordance with APB No. 25 and plan to transition to a fair value-based method of accounting for stock option plans. We will use the prospective method of transition as described in Statement No. 148.
Minority Interest. Minority interest on the consolidated balance sheets includes third-party investments in which are not wholly-owned consolidated entities. The net pre-tax results attributed to minority interest holders in consolidated entities are classified in minority interest in the consolidated statements of operations. In addition, minority interest at December 31, 2001 included $867 million related to Catlin Associates LLC, an entity formed in connection with our Black Thunder financing, which was reclassified to debt during 2002. Please see Note 10-Debt beginning on page, for further discussion.
New Accounting Pronouncements. As noted above, in June 2001, the FASB issued Statement No. 143, which we adopted January 1, 2003. See further discussion above in -Other Contingencies beginning on page.
As noted above, during 2002 the EITF reached several consensuses in EITF Issue 02-03. See further discussion above in -Revenue Recognition beginning on page.
In April 2002, the FASB issued Statement of Financial Accounting Standards No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections” (“Statement No. 145”). The adoption of Statement No. 145 effective January 1, 2003 is not expected to impact us.
In July 2002, the FASB issued Statement of Financial Accounting Standards No. 146, “Accounting for Exit or Disposal Activities” (“Statement No. 146”). Statement No. 146 addresses issues regarding the recognition, measurement and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently accounted for pursuant to the guidance that the EITF has set forth in EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” Statement No. 146 requires costs to be accrued as incurred rather than when an approved plan is in place. The scope of Statement No. 146 also includes (1) costs related to terminating a contract that is not a capital lease and (2) termination benefits that employees who are involuntarily terminated received under the terms of a one-time benefit arrangement that is not an ongoing benefit arrangement or an individual deferred compensation contract. Statement No. 146 will be effective for exit
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or disposal activities that are initiated after December 31, 2002, although early adoption of the standard is encouraged. If we had adopted Statement No. 146 early, $45 million of our fourth quarter restructuring charge, which is discussed in Note 3-Dispositions, Discontinued Operations and Acquisitions beginning on page, would have been recognized in future periods.
In November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FIN 45”). FIN 45 elaborates on the disclosures to be made by a guarantor about its obligations under certain guarantees. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. As required by FIN 45, we adopted the disclosure requirements on December 31, 2002, and we will adopt the initial recognition and measurement provisions on a prospective basis for guarantees issued or modified after December 31, 2002. We believe the adoption of the recognition/measurement provisions will not have a material impact on our financial statements.
In December 2002, the FASB issued Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure” (“Statement No. 148”). Statement No. 148 amends FASB Statement No. 123, and provides alternative methods of transition (prospective, modified prospective, or retroactive) for entities that voluntarily change to the fair value-based method of accounting for stock-based employee compensation in a fiscal year beginning before December 16, 2003. Statement No. 148 requires prominent disclosure about the effects on reported net income of an entity’s accounting policy decisions with respect to stock-based employee compensation. We are evaluating the prospects of transitioning during 2003 to a fair value-based method of accounting for stock-based compensation and are assessing the most appropriate transitional method to adopt (prospective, modified prospective, or retroactive) as described under Statement No. 148.
In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities-an Interpretation of ARB No. 51” (“FIN 46”). FIN 46 addresses the consolidation of “variable interest entities” having certain characteristics. In summary, this interpretation increases the level of risk that must be assumed by equity investors in special purpose entities. FIN 46 requires that the equity investor have significant equity at risk (minimum of 10% with few exceptions, increased from 3% under previous guidance) and hold a controlling interest, evidenced by voting rights, risk of loss and the benefit of residual returns. If the equity investor is unable to evidence these characteristics, the entity that does retain these ownership characteristics will consolidate the variable interest entity. We are in the process of evaluating the impact of FIN 46. While we have not entered into any arrangements in 2003 that would be subject to FIN 46, we may have existing arrangements that are impacted. FIN 46 is applicable immediately to variable interest entities created or obtained after January 31, 2003. For variable interest entities acquired before February 1, 2003, FIN 46 is applicable as of July 1, 2003.
NOTE 3-DISPOSITIONS, DISCONTINUED OPERATIONS AND ACQUISITIONS
DISPOSITIONS
As part of our restructuring plan, significant portions of our operations were sold during 2002, many of which were accounted for as Discontinued Operations under Statement No. 144, as further discussed below.
Discontinued Operations
In 2002, the following operations were discontinued and subsequently sold:
Northern Natural. In November 2001, Dynegy Inc. acquired 1,000 shares of Series A Preferred Stock (“Series A Preferred Stock”) in Northern Natural Gas Company (“Northern Natural”) for $1.5 billion. We
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concurrently acquired an option to purchase all of the equity of Northern Natural’s indirect parent company. We exercised our option to acquire the indirect parent of Northern Natural in November 2001 upon termination of a merger agreement with Enron, and the closing of the option exercise occurred on January 31, 2002.
On August 16, 2002, Dynegy Inc. and Dynegy Holdings Inc. sold all of their investment in the preferred stock and the common stock, respectively, of Northern Natural to MidAmerican Energy Holdings Company (“MidAmerican”) for $879 million in cash, after adjustment for changes in working capital. Pursuant to the sales agreement, 95 percent of the purchase price was allocated to the preferred stock held by Dynegy Inc. and five percent of the purchase price was allocated to the common stock held by us. Under the terms of this agreement, MidAmerican acquired all of the common and preferred stock of Northern Natural and assumed all of Northern Natural’s $950 million of debt, which debt had a book value of approximately $890 million. We incurred a pre-tax loss of $63 million ($45 million after-tax) associated with the sale, including all adjustments for changes in working capital.
On September 30, 2002, we sold $90 million in 6.875 percent senior notes of Northern Natural due May 2005 for approximately $96 million including accrued interest of $2 million. We acquired the notes at par value in April 2002 pursuant to a tender offer that we agreed to effect in order to obtain a bondholder consent in connection with the acquisition of Northern Natural. The gain on sale of approximately $4 million is reflected in other income on the accompanying consolidated statements of operations and is net of accrued interest.
United Kingdom Storage. In the fourth quarter 2001, we completed the purchase of BG Storage Limited (“BGSL”), a wholly owned subsidiary of BG Group plc. Under the terms of the purchase agreement, we paid approximately £421 million (approximately $595 million at November 28, 2001) for BGSL and its existing assets. The assets, which are located in the United Kingdom (“U.K.”), consisted primarily of the Hornsea onshore gas storage facility in the U.K., the Rough offshore natural gas fields in the North Sea and the Easington natural gas processing terminal on the East Yorkshire coast.
BGSL’s results of operations are included in our consolidated statement of operations beginning December 1, 2001 as part of our WEN segment. A condensed balance sheet as of the acquisition date is as follows (in millions):
On September 30, 2002, we sold a subsidiary that owned the Hornsea onshore natural gas storage facility in the U.K. for net cash proceeds of approximately $189 million. There was no gain/loss recognized on this sale. On
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November 14, 2002, we sold the subsidiaries that owned the Rough offshore natural gas field in the North Sea and the Easington natural gas processing terminal on the East Yorkshire coast for cash proceeds of approximately $500 million, thereby completing the disposition of all BGSL-related assets. We recognized a pretax gain on the sale of Rough of approximately $30 million ($5 million after-tax).
Global Liquids. As a result of our decision to exit the international LPG trading and transportation business, in December 2002 we sold our Dynegy Global Liquids business, which was included in our DMS segment, to Trammo Gas International Inc., a wholly owned subsidiary of Transammonia Inc. The effective date of the sale was January 1, 2003. Consideration for the sale will be a cash payment in 2007 based on a 12.5 percent share of actual cumulative EBITDA of the assets sold over the next five years (2003 through 2007), capped at $8 million. We recorded pre-tax write-downs and accruals totaling $27 million associated with this transaction in 2002.
Approximately $12 million of the $27 million charge noted above was our investment in Energy Infrastructure (India) Ltd. (“EIIL”). We had a 37.5 percent ownership interest in EIIL valued at $12 million that we accounted for under the equity method. The success of the EIIL project, which was still in the start-up phase, was heavily dependent on our expertise and global LPG resourcing capabilities. As a result of our exit from the global liquids business, our involvement in the future operations of the project has been significantly reduced. We expect to receive no value or cash flows for our current investment in the project. As a result, we wrote down our investment in this project to zero at December 31, 2002. The remaining 2002 charges associated with this disposition included the write-off of a logistics and accounting computer system not acquired by the purchaser, and other related restructuring costs.
The following table summarizes information related to our discontinued operations ($ in millions):
Other Significant Dispositions
Canadian Assets. In August 2002, we completed the sale of a significant portion of our Canadian crude oil business to The Seminole Group Inc. In November 2002, we completed the sale of a portion of our Canadian natural gas marketing business to The Seminole Group Inc. The pre-tax loss on the sale was approximately $7 million. The remaining Canadian business consists primarily of existing power marketing positions and physical gas in storage.
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Hackberry Terminal. Consistent with our restructuring plan, in early 2003 we entered into an agreement to sell 100 percent of our membership interest in Hackberry LNG Terminal LLC, the entity we formed in connection with our proposed LNG terminal/gasification project in Hackberry, Louisiana, to Sempra LNG Corp., a subsidiary of San Diego-based Sempra Energy. The transaction is subject to the completion of specified closing conditions. Under the terms of the agreement, Sempra LNG Corp. will make an initial payment of $20 million to us, with additional contingent payments based upon project development milestones. Additionally, we are entitled to a portion of the return on the project if performance targets are achieved in the future. The planned facility will be capable of sending out 1.5 billion cubic feet per day of natural gas and will have two docks and storage capability of 10.4 billion cubic feet equivalent. Pending further approvals, commercial operation is expected as early as 2007.
2000 Dispositions. In the first quarter 2000, we sold our domestic crude oil marketing and trading business, which was included in the results of our DMS segment prior to its sale. We recognized an after-tax loss on the sale of $11 million, which is included in loss (gain) on asset sales on our consolidated statements of operations. Also in the first quarter of 2000, we sold our Mid-Continent gas processing assets, the results of which were included in the results of the DMS segment prior to the sale, and recognized a $6 million after-tax loss, which is included in loss (gain) on asset sales on our consolidated statements of operations. In the third quarter 2000, we sold our 25% participating preferred interest in Accord, which was included in the results of our WEN segment prior to its sale. We received cash proceeds of $95 million, and recognized an after-tax gain of $58 million. The gain is included in loss (gain) on asset sales on our consolidated statements of operations. Finally, during 2000 we sold interests in certain Qualifying Facilities, which were included in the results of our WEN segment prior to their sale, pursuant to statutory requirements related to Dynegy Inc.’s Illinova acquisition. We received cash proceeds of $257 million on those sales and recognized an after-tax gain of $34 million. The gain is included in loss (gain) on asset sales on our consolidated statements of operations.
ACQUISITIONS
DNE. In the first quarter of 2001, we acquired DNE power generation facilities in New York. The DNE facilities consist of a combination of base load, intermediate and peaking facilities aggregating 1,700 MW. The facilities are located approximately 50 miles north of New York City and were acquired for approximately $903 million cash, plus inventory and certain working capital adjustments. In May 2001, two of our subsidiaries completed a sale-leaseback transaction to provide the term financing with respect to the DNE facilities. Under the terms of the sale-leaseback transaction, our subsidiaries sold certain plants and equipment and agreed to lease them back for terms expiring within 34 years, exclusive of renewal options.
Consideration Paid for Acquisitions. Consideration paid for the above described 2002, 2001 and 2000 business acquisitions was as follows ($ in millions):
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NOTE 4-RESTRUCTURING AND IMPAIRMENT CHARGES
In 2002, we recorded pre-tax restructuring and impairment charges of $392 million relating to various areas of our operations. The table below provides the amounts of such charges by business area and the caption in which such charges are reflected in the consolidated statements of operations ($ in millions):
Severance and Other Restructuring Costs. In October 2002, we announced a restructuring plan designed to improve operational efficiencies and performance across our lines of business, including the adoption of a decentralized business structure consisting of a streamlined corporate center and operating units in power generation, natural gas liquids and regulated energy delivery. As part of the restructuring, we also announced we would exit third-party risk management aspects of the marketing and trading business. The decision to exit this business is expected to reduce our collateral requirements and overall corporate expenses. During the restructuring period and thereafter, we will maintain the resources and make the necessary arrangements to meet our customer commitments, including retaining personnel and risk management capabilities. This decision to exit third-party risk management aspects of the marketing and trading business will not change the commercial activities of our midstream or generation businesses. The midstream business will continue to manage commodity price risk associated with its operations related to fuel procurement and the marketing of natural gas liquids. Further, the generation business will continue to manage commodity price risk existing in its physical asset positions through optimizing fuel procurement and the marketing of power in connection with our generation capacity including entering into and unwinding forward hedge positions.
In addition, in the second quarter 2002, we recognized a charge for severance benefits.
As a result of these items, we recognized a charge of $207 million ($135 million after-tax) during 2002, as detailed below ($ in millions):
In accordance with EITF 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring),” we recognized $61 million in charges ($40 million after-tax) associated with cancellation fees and accruals for the termination of operating leases. These accruals are not discounted.
In addition, we recognized severance charges of $103 million ($67 million after-tax) related to severance benefits for approximately 1,089 employees, who were from various segments and included all staffing levels, including our former Chief Executive Officer, former President and former Chief Financial Officer.
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Approximately $4 million was reclassified to Discontinued Operations in the third quarter related to the sale of Northern Natural.
A substantial amount of the balance at December 31, 2002 relates to severance that has not been paid to our former Chief Executive Officer, former President and former Chief Financial Officer, each of whom has instituted an arbitration proceeding related to this severance. Please read Note 14-Commitments and Contingencies beginning on page for further discussion.
In April 2003, we made a payment to the Internal Revenue Service associated with a tax obligation incurred by our former Chief Executive Officer in relation to a May 2002 stock option exercise. This exercise was effected by a family limited partnership controlled by Mr. Watson to which he had previously transferred approximately 2.4 million options to acquire Dynegy stock. The April 2003 payment was made in response to an Internal Revenue Service inquiry arising from the fact that no tax withholdings were made at the time of the exercise. It is intended that this payment to the Internal Revenue Service will be offset against any other payments determined to be owed to Mr. Watson as a result of the ongoing arbitration proceedings between the parties. This payment does not impact our results of operations because the amount of the severance accrual we previously established for Mr. Watson in connection with his 2002 resignation exceeds the amount of such payment.
The following is a schedule of 2002 activity for the liabilities recorded associated with these charges ($ in millions):
Impairment losses of $15 million ($10 million after-tax) were also incurred as a result of the corporate restructuring plan for certain technology assets no longer being utilized in accordance with Statement 144. The remaining $28 million ($18 million after-tax) of the charge represents accelerated depreciation due to a change in the estimated useful life for leasehold improvements and technology assets related to the abandonment of those assets. These charges are included in depreciation and amortization expense.
Impairment of generation investments. In conjunction with our review of the carrying value of goodwill in the third quarter of 2002 (see Note 9-Goodwill, beginning on page for further discussion), we assessed the carrying value of our generation portfolio on an asset-by-asset basis. The generation portfolio includes wholly-owned generating facilities, which are reflected in property, plant and equipment, as well as investments in partnerships and limited liability companies that own generating facilities, which are reflected in unconsolidated investments. Based on this review, the carrying value associated with the wholly-owned generation facilities was considered realizable. However, some investments were considered impaired, resulting in a pre-tax charge of $117 million. The diminution in the fair value of these investments is a result of depressed energy prices and an increase in the rate of return required by investors to enter into the power generating business.
Impairment of technology investments. During the first six months of 2002, the valuations of technology investments were assessed in light of Dynegy Inc.’s decision to pursue partnership and sale opportunities for
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their communications business. These investments were originally entered into in order to leverage existing commercial relationships or as a means of expanding new communications relationships. Historically, these investments were viewed as strategic and core to Dynegy Inc.’s communications strategy. Accordingly, we expected to hold these investments for the long term and viewed trends in the sector as cyclical. These investments include ownership in public and private companies and investment funds focused in the technology sector. The continued downturn in the technology sector during the second quarter 2002 combined with Dynegy Inc.’s change in strategy resulted in an impairment charge relative to these investments. We recorded a charge of $10 million ($7 million after-tax) for devaluation of investments resulting from unfavorable market conditions in the second quarter 2002.
These investments were re-evaluated at September 30, 2002 based on our inability to sell certain investments for their adjusted carrying values and the continued depressed conditions in the technology sector. Based on this assessment, the remaining carrying values of these investments were written off, resulting in a charge of $7 million ($4 million after-tax). The cumulative charge related to technology investments for the year ended December 31, 2002 was $17 million ($11 million after-tax).
Impairment of other obsolete assets. As a result of our decision to exit third-party risk management aspects of the marketing and trading business, our investment in Dynegydirect was written off in the third quarter 2002, resulting in a pre-tax charge of $25 million ($16 million after-tax). We also recognized a $14 million ($9 million after-tax) charge associated with the impairment of a generation turbine, as its fair value calculated in accordance with Statement No. 144 was less than its carrying value. We recognized a pre-tax charge of $12 million ($8 million after-tax) in the second quarter 2002 related to the retirement of partially depreciated information technology equipment and software replaced during the quarter with new system applications and arrangements as well as miscellaneous deposits that are not expected to provide future value.
NOTE 5-COMMERCIAL OPERATIONS, RISK MANAGEMENT ACTIVITIES AND FINANCIAL INSTRUMENTS
Our operations and periodic returns 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 risk, management estimations, strategic investment decisions, changes in competition, operational risks, environmental risks and changes in regulations.
The potential for changes in the market values of our commodity, interest rate and currency portfolios are referred to as “market risk.” A description of these market risks is set forth below:
•
Commodity price risks result from exposures to changes in spot prices, forward prices and volatilities of commodities, such as electricity, natural gas and other similar products;
•
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; and
•
Currency rate risks result from exposures to changes in spot prices, forward prices and volatilities of currency rates.
We seek 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 or our inability to transact as a result of reduced credit capacity or other factors. We cannot guarantee the ultimate effectiveness of our risk management activities.
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We generally attempt to balance our fixed-price physical and financial purchase and sales commitments in terms of contract volumes, and the timing of performance and delivery obligations. However, we may, at times, have a bias in the market within guidelines established by management and by our Board of Directors, resulting from the management of our portfolio. In addition, as a result of marketplace illiquidity, our creditworthiness and other factors, we may, at times, be unable to hedge our portfolio fully for certain market risks.
The financial performance and cash flow derived from certain merchant generating capacity (e.g., peaking facilities) are impacted annually, either favorably or unfavorably, by changes in, and the relationship between, the cost of the commodity fueling the facilities and electricity prices, which in turn influences the volume of electricity generated by these assets.
Operating results associated with natural gas gathering, processing and fractionation activities are sensitive to changes in NGL prices and the availability of inlet volumes. In addition, similar to peaking electricity generating facilities, straddle processing plants are impacted by changes in, and the relationship between, natural gas and NGL prices, which in turn influence the volumes of gas processed at these facilities. The impact from changes in NGL prices on upstream operations results principally from the nature of contractual terms under which natural gas is processed and products are sold. The availability of inlet volumes directly affects the utilization and profitability of this segment’s businesses. Commodity price volatility may also affect operating margins derived from our NGL marketing operations.
Quantitative and Qualitative Market Risk Disclosures. In addition to applying business judgment, we use a number of quantitative tools to manage our exposure to market risk. These tools include:
•
Risk limits based on a summary measure of market risk exposure, referred to as VaR; and
•
Stress and scenario analyses as performed daily that measure the potential effects of various market events, including substantial swings in volatility factors, absolute commodity price changes and the impact of interest rate movements.
VaR represents the potential loss in value of our enterprise-wide marketing portfolio due to adverse market movements over a defined time horizon with a specified confidence level.
The modeling of the risk characteristics of our various portfolios involves a number of assumptions and approximations. We estimate VaR using a JP Morgan RiskMetrics™ approach assuming a one-day holding period and a 95 percent confidence level. 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, these historical data are weighted to give greater importance to more recent observations. Given its reliance on historical data, VaR is most 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.
Credit and Market Reserves. In connection with the market valuation of our energy commodity contracts, we maintain certain reserves for a number of risks associated with these future commitments. Among others, these include reserves for credit risks based on the financial condition of counterparties, reserves for price and product location (“basis”) differentials and consideration of the time value of money for long-term contracts.
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Counterparties in our marketing portfolio consist principally of commercial and industrial companies, utility and power generators, financial institutions and oil and gas producers. The creditworthiness of these counterparties may impact overall exposure to credit risk, either positively or negatively. However, with regard to our counterparties, we maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings, financial condition and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.
Based on these policies, our current exposures and our credit reserves, we do not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance. As a result of Enron’s bankruptcy, we reserved an after-tax amount of $84 million in the fourth quarter 2001 related to our net exposure for commercial transactions with that entity. For further discussion of this matter, see Note 14-Commitment and Contingencies beginning on page.
Accounting for Derivative Instruments and Hedging Activities. The Financial Accounting Standards Board issued, and subsequently amended, Statement No. 133, which became effective January 1, 2001. Provisions in Statement No. 133, as amended, affect our accounting and disclosure of certain contractual arrangements and operations. Under Statement No. 133, as amended, all derivative instruments are recognized in the balance sheet at their fair values and changes in fair value are recognized immediately in earnings, unless such instruments qualify, and are designated, as hedges of future cash flows, fair values, net investments or qualify, and are designated, as normal purchases and sales. For derivatives treated as hedges of future cash flows, the effective portion of changes in fair value is recorded as a component of accumulated other comprehensive loss until the related hedged items impact earnings. Any ineffective portion of a cash flow hedge is reported in earnings immediately. For derivatives treated as fair value hedges, changes in the fair value of the derivative and changes in the fair value of the related asset or liability are recorded in current period earnings. For derivatives treated as hedges of net investment in foreign operations, the effective portion of changes in the fair value of the derivative is recorded in the foreign currency translation adjustment, a component of accumulated other comprehensive loss. Derivatives treated as normal purchases or sales are recorded and recognized in income using accrual accounting.
We recorded the impact of the adoption of Statement No. 133, as amended, as a cumulative effect adjustment in our consolidated results on January 1, 2001. The amounts recorded are as follows ($ in millions):
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Accumulated other comprehensive loss, net of tax is included in stockholders’ equity on the consolidated balance sheets as follows ($ in millions):
Additional disclosures required by Statement No. 133, as amended, are provided in the following paragraphs.
From time to time, we may enter into various financial derivative instruments that qualify as cash flow hedges. Instruments related to our power generation and midstream liquids businesses are entered into for purposes of hedging forward fuel requirements for power generation and fractionation facilities and locking in future margin in the domestic midstream liquids and power marketing businesses. In addition, prior to exiting the Global Liquids business, we utilized these instruments to hedge price risks associated with this business. Interest rate swaps are used to convert the floating interest-rate component of some obligations to fixed rates.
During the years ended December 31, 2002 and 2001, there was no material ineffectiveness from changes in fair value of hedge positions, and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. Additionally, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.
The balance in other comprehensive income at December 31, 2002 is expected to be reclassified to future earnings, contemporaneously with the related purchases of fuel, sales of electricity or natural gas liquids and payments of interest, as applicable to each type of hedge. Of this amount, approximately $10 million of after-tax losses is estimated to be reclassified into earnings during 2003. The actual amounts that will be reclassified to earnings over the next year and beyond could vary materially from this estimated amount as a result of changes in market conditions.
From time to time, we may also enter into derivative instruments that qualify as fair-value hedges. We used interest rate-swaps to convert a portion of our nonprepayable fixed-rate debt into variable-rate debt. During the twelve months ended December 31, 2002 and 2001, there was no ineffectiveness from changes in fair value of hedge positions, and no amounts were excluded from the assessment of hedge effectiveness. Additionally, no amounts were recognized in relation to firm commitments that no longer qualified as fair-value hedge items.
We have investments in foreign subsidiaries, and the net assets of these subsidiaries are exposed to currency exchange-rate volatility. We use derivative financial instruments, including foreign exchange forward contracts and cross currency interest rate swaps, to hedge this exposure. For the years ended December 31, 2002 and 2001, zero and approximately $18 million of net losses related to these contracts were included in the cumulative translation adjustment, respectively. This amount neutralizes the cumulative translation gains of the underlying net investments in foreign subsidiaries for the period the derivative financial instruments were outstanding.
Fair Value of Financial Instruments. The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standards
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No. 107, “Disclosures About Fair Value of Financial Instruments.” We have determined the estimated fair-value amounts using available market information and selected valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies could have a material effect on the estimated fair-value amounts.
The carrying values of current financial assets and liabilities approximate fair values due to the short-term maturities of these instruments. The carrying amounts and fair values of debt are included in Note 10-Debt beginning on page. The carrying amounts and fair values of our other financial instruments were ($ in millions):
The fair value of our Preferred Securities of a Subsidiary Trust, were based on quoted market prices by financial institutions that actively trade these debt securities. The fair value of interest rate and commodity risk-management contracts were based upon the estimated consideration that would be received to terminate those contracts in a gain position and the estimated cost that would be incurred to terminate those contracts in a loss position.
The absolute notional contract amounts associated with the derivative instruments designated as hedges were as follows:
ABSOLUTE NOTIONAL CONTRACT AMOUNTS
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NOTE 6-CASH FLOW INFORMATION
Detail of supplemental disclosures of cash flow and non-cash investing and financing information was ($ in millions):
The businesses acquired included: 2002-Northern Natural and 2001-BGSL. See Note 3-Dispositions, Discontinued Operations and Acquisitions, beginning on page for more information regarding these acquisitions.
NOTE 7-PROPERTY, PLANT AND EQUIPMENT
Investments in property, plant and equipment consisted of ($ in millions):
Interest capitalized related to costs of projects in process of development totaled $16 million, $19 million and $30 million for the years ended December 31, 2002, 2001 and 2000, respectively.
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NOTE 8-UNCONSOLIDATED INVESTMENTS
Our unconsolidated investments consist primarily of investments in affiliates that we do not control but where we have significant influence over operations. These investments are accounted for by the equity method of accounting. Our share of net income from these affiliates is reflected in the consolidated statements of operations as earnings (losses) of unconsolidated investments. Our principal equity method investments consist of entities that operate generation assets and natural gas liquids assets. We entered into these ventures principally for the purpose of sharing risk and leveraging existing commercial relationships. These ventures maintain independent capital structures and have financed their operations either on a non-recourse basis to us or through their ongoing commercial activities. We hold investments in joint ventures in which ChevronTexaco or its affiliates are investors. For additional information about these investments, please read Note 11-Related Party Transactions beginning on page.
A summary of our unconsolidated investments is as follows ($ in millions):
Cash distributions received from our equity investments during 2002, 2001 and 2000 were $77 million, $87 million and $109 million, respectively. Our investment balances include unamortized purchase price differences of $49 million and $151 million at December 31, 2002 and 2001, respectively. The unamortized purchase price differences represent the difference between our purchase price and our share of the investee’s book value at time of acquisition. Undistributed earnings from our equity investments included in retained earnings (deficit) at December 31, 2002 and 2001 totaled $144 million and $155 million, respectively.
Generation Investments. Generation investments include ownership interests in seven joint ventures that own fossil fuel electric generation facilities as well as a limited number of international ventures. Our ownership is 50 percent in the majority of these ventures. Our aggregate net investment of $498 million at December 31, 2002 represents approximately 2,400 MW of net generating capacity. Our most significant investment in generating capacity is our interest in West Coast Power, representing approximately 1,400 MW of net generating capacity in California. Our net investment in West Coast Power totaled approximately $287 million and $330 million at December 31, 2002 and December 31, 2001, respectively. West Coast Power provided equity earnings of approximately $17 million, approximately $162 million and $122 million in the years ended December 31, 2002, 2001 and 2000, respectively. Equity earnings during 2002 were negatively impacted by a $100 million increase ($50 million net to us) in West Coast Power’s allowance for doubtful accounts as well as a pre-tax impairment of $117 million in multiple equity investments based on a fair value assessment, as further discussed in Note 4-Restructuring and Impairment Charges beginning on page. On November 22, 2002, a petition was filed by several former officers of NRG Energy, Inc. (“NRG”), the parent company of our partner in West Coast Power and another joint venture, to put NRG in involuntary bankruptcy. NRG and the original petitioners reached a settlement agreement on February 17, 2003, in which the original petitioners agreed to cooperate with NRG to secure dismissal of the petition. One intervening petitioning creditor remains who did not withdraw its objection to NRG’s motion to dismiss. A hearing was held in early April 2003 on the motion to
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dismiss, after which the Judge took the matter under advisement and indicated he would have a decision shortly. We cannot predict with certainty the effects of these or similar actions by NRG on the operations or collateral obligations of these two joint ventures.
During the first quarter 2003, we completed the sale of our 20% equity investment in Southstar Energy Services LLC. We received cash proceeds of approximately $20 million and recognized a gain on the sale of approximately $1.5 million before taxes.
Midstream Investments. At December 31, 2002, Midstream investments included a 23 percent ownership interest in a venture that operates a natural gas liquids processing, extraction, fractionation and storage facility in the Gulf Coast region as well as a 39 percent ownership interest in a venture that fractionates NGLs on the Gulf Coast. Our midstream investments at December 31, 2001 also included our investment in West Texas LPG Pipeline Limited Partnership (“WTLPS”), which was sold to ChevronTexaco in August 2002. Please read Note 11-Related Party Transactions, beginning on page for further discussion of this transaction.
Summarized aggregate financial information for the generation and midstream investments and our equity share thereof was ($ in millions):
(1)
The financial data for 2000 is exclusive of amounts attributable to our investment in Accord as data was unavailable for these periods. For competitive reasons, Accord was unwilling to provide to us detailed financial information concerning its operations. We contractually agreed not to require the production of such information in our negotiations with Accord. Our share of Accord earnings for the year ended December 31, 2000 totaled $9 million. We sold our investment in Accord in the third quarter 2000.
Other Investments. In addition to these equity investments, we hold interests in companies for which we do not have significant influence over the operations. These investments are accounted for by the cost method. Such investments totaled $39 million at December 31, 2001. We also owned securities that had a readily determinable fair market value and were considered available-for-sale. The market value of these investments at December 31, 2002 and 2001 was estimated to be zero and $9 million, respectively. During 2001, we recognized a $19 million pre-tax loss on a technology investment due to impairments that were determined by management to be other-than-temporary. During 2002, we wrote down the remaining values of our available for-sale securities. See Note 4-Restructuring and Impairment Charges beginning on page.
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NOTE 9-GOODWILL
The changes in the carrying amount of goodwill for each of our reportable business segments for the year ended December 31, 2002 were as follows ($ in millions):
Significant components of the changes in goodwill during 2002 included the following:
We adopted Statement No. 142 effective January 1, 2002, and, accordingly, tested for impairment all amounts recorded as goodwill. We determined that no goodwill was impaired. The fair value of our reporting segments was estimated using the expected discounted future cash flows.
During 2002, the value of goodwill associated with our WEN segment was determined to be impaired, resulting in our recognizing a charge of $724 million. The fair values of the respective components of this segment were estimated utilizing the expected discounted future cash flows. The primary factors leading to this impairment were: (1) the reduction in near-term power prices; (2) an increase in the rate of return required for investors to enter the energy merchant sector; and (3) our decision to exit third-party risk management aspects of the marketing and trading business. The impairment charge is reflected in the consolidated statement of operations as a goodwill impairment.
Also in 2002, goodwill associated with the acquisition of Northern Natural was recorded and removed when Northern Natural was sold. See Note 3-Dispositions, Discontinued Operations and Acquisitions, beginning on page for additional discussion of the sale of Northern Natural.
All charges related to goodwill during 2002 are the same on a pre-tax or an after-tax basis.
The following table shows what our net income would have been in 2001 and 2000 if goodwill had not been amortized during those periods, compared to the net loss we recorded for 2002 ($ in millions).
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NOTE 10-DEBT
Notes payable and long-term debt consisted of the following at December 31 ($ in millions):
Aggregate maturities of the principal amounts of all long-term indebtedness are: 2003-$484 million; 2004-$156 million; 2005-$1,299 million; 2006-$228 million; 2007-$184 million and beyond $1,409 million.
Revolvers and Commercial Paper. On April 29, 2002, we closed a $900 million unsecured revolving credit agreement with a syndicate of commercial banks. This facility was scheduled to mature on April 28, 2003 but has been restructured and extended as described below. Generally, borrowings under this credit agreement bore interest at a Eurodollar rate plus a margin determined based on our unsecured debt ratings. Facility fees were payable on the full amount of the facility and were determined based on unsecured debt ratings. As of December 31, 2002, amounts outstanding under this facility included $128 million of borrowings and $624 million in letters of credit. An additional $248 million in letters of credit was outstanding at December 31, 2002 under our $400 million revolving credit agreement. The facility did not contain a “term-out” provision permitting extension of the maturity for borrowings under the facility beyond the facility’s April 28, 2003 maturity date. As such, the amounts outstanding under this facility were classified as current at December 31, 2002.
At December 31, 2002, we had no outstanding commercial paper. The weighted average interest rate at December 31, 2001 on the $6 million outstanding under our commercial paper program was 3.2 percent.
During the year ended December 31, 2002, we repaid commercial paper borrowings and revolving credit facilities of approximately $614 million in the aggregate and borrowed an aggregate of approximately $136 million under our revolving credit facilities. Additionally, during the year ended December 31, 2002, we issued an aggregate of $495 million of letters of credit under our revolving credit facilities.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Bank Restructuring
On April 2, 2003, we entered into a $1.66 billion bank credit facility consisting of:
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a $1.1 billion secured revolving credit facility (the “revolving facility”) and a $200 million secured term loan (“Term A facility”), each of which matures on February 15, 2005; and
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a $360 million secured term loan (“Term B facility”) that matures on December 15, 2005.
The credit facility replaces, and preserves the commitment of each lender under, our $900 million and $400 million revolving credit facilities, which had maturity dates of April 28, 2003 and May 27, 2003, respectively, and Dynegy Inc.’s $360 million Polaris communications lease, which had a maturity date of December 15, 2005. The credit facility will provide funding for general corporate purposes. The revolving facility is also available for the issuance of letters of credit. Borrowings under the credit facility will bear interest, at our option, at (i) a base rate plus 3.75% per annum or (ii) LIBOR plus 4.75% per annum. A letter of credit fee will be payable on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 4.75% of the undrawn amount. An unused commitment fee of 0.50% will be payable on the unused portion of the revolving facility.
Subject to restrictions contained in the credit facility, amounts repaid under the revolving facility may be reborrowed. The full amounts of the borrowings under the Term A facility and the Term B facility were borrowed at the closing, and borrowings repaid under these facilities may not be reborrowed.
The credit facility contains mandatory prepayment events. The credit facility must, subject to specified exceptions, be repaid and commitments permanently reduced with:
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100% of the net cash proceeds of all non-ordinary course asset sales;
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50% of the net cash proceeds from the issuance of equity or subordinated debt;
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100% of the net cash proceeds from the issuance of senior debt; and
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50% of extraordinary receipts.
The credit facility provides for no amortization of principal amounts outstanding prior to the maturity dates except upon the occurrence of such a prepayment event.
Subject to specified exceptions, our obligations under the credit facility are guaranteed by Dynegy Inc. and substantially all of Dynegy Inc.’s direct and indirect subsidiaries, excluding (i) IP and DGC and their respective subsidiaries, (ii) most foreign subsidiaries, dormant subsidiaries and subsidiaries with de minimus value and (iii) subsidiaries that are unable to become guarantors due to existing contractual or legal restrictions.
Subject to specified exceptions and permitted liens, the lenders under the credit facility received a first priority lien in substantially all the assets of Dynegy Inc., us and certain of the subsidiary guarantors to the extent practicable and permitted by existing contractual arrangements, excluding IP and DGC and their respective subsidiaries. The lenders also received a first priority lien in the ownership interests in Dynegy Inc.’s direct and indirect subsidiaries, including us but excluding (i) IP and DGC and their respective subsidiaries, (ii) most foreign subsidiaries, dormant subsidiaries and subsidiaries with de minimus value and (iii) subsidiaries whose ownership interests may not be pledged due to existing contractual or legal restrictions. The lenders also received a second priority lien in all material assets of DMG, subject to the first priority lien granted to the lenders under the Black Thunder financing. Our obligations under the Project Alpha transaction and CoGen Lyondell and Riverside generating facility leases were ratably secured with the same assets pledged to the lenders under the credit facility as required by the terms of those facilities.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The credit facility contains affirmative covenants relating to, among other things, financial statements; compliance and other certificates; notices of specified events; payment of obligations; preservation of existence; maintenance of properties; maintenance of insurance; compliance with laws; maintenance of books and records; inspection rights; use of proceeds; guarantee obligations and security; compliance with environmental laws; preparation of environmental reports; further assurances; material contracts; distribution of cash proceeds and extraordinary receipts by subsidiaries; and mortgaged property. The credit facility contains negative covenants relating to, among other things, liens; investments; indebtedness; fundamental changes; dispositions; restricted payments; changes in business; transactions with affiliates and non-loan parties; burdensome agreements; use of proceeds; amendments to organizational documents; accounting changes; prepayments of indebtedness; material contracts; swap contracts and off-balance sheet arrangements; formation of subsidiaries; the CoGen Lyondell and Riverside facilities; and amendments to the Dynegy Inc. Series B preferred stock held by ChevronTexaco. The credit facility also contains financial and capital expenditure-related covenants, which are described in detail below.
The credit facility generally prohibits Dynegy Inc. and its subsidiaries, including us, subject to various customary and other exceptions, from incurring additional debt. Notwithstanding this restriction, we may issue “exchange debt,” or debt issued in exchange for our outstanding senior unsecured debt. Any such exchange debt may provide for guarantees that result in such debt being structurally senior to our outstanding senior unsecured debt. Any exchange debt issued would be subject to the following restrictions:
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for exchange debt offered in respect of our senior unsecured debt maturing in 2005 and 2006,
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if the maturity of the exchange debt is prior to March 15, 2007, then the aggregate principal amount of exchange debt issued generally cannot exceed 66% of the aggregate principal amount of our senior unsecured debt that is exchanged; and
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if the maturity of the exchange debt is on or after March 15, 2007, then the aggregate principal amount of exchange debt issued generally cannot exceed the aggregate principal amount of our senior unsecured debt that is exchanged;
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for exchange debt offered in respect of our senior unsecured debt maturing in 2011, 2012, 2018 and 2026,
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the aggregate principal amount of exchange debt issued generally cannot exceed the aggregate principal amount of our senior unsecured debt that is exchanged; and
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the maturity of the exchange debt must be after December 31, 2009; and
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the aggregate cash interest expense of any exchange debt cannot exceed the aggregate cash interest expense of our senior unsecured debt that is exchanged.
The credit facility generally prohibits Dynegy Inc. and its subsidiaries, including us, from pre-paying, redeeming or repurchasing outstanding debt or preferred stock. Notwithstanding this restriction, Dynegy Inc. and its subsidiaries, including us, may repurchase or redeem up to $300 million in our senior notes or Dynegy Inc. Series B preferred stock held by ChevronTexaco subject to the following restrictions:
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the first $100 million in repurchases of our senior notes requires a concurrent permanent reduction in commitments under the credit facility of $100 million, the second $100 million in repurchases requires a concurrent permanent reduction in commitments under the credit facility of $200 million, and the third $100 million in repurchases requires a concurrent permanent reduction in commitments under the credit facility of $300 million;
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no concurrent permanent reduction in commitments under the credit facility is required if our senior notes are repurchased with net cash proceeds attributable to extraordinary receipts or the issuance of equity or subordinated debt; and
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only $50 million of the $300 million may be used to repurchase our senior notes that mature on or after April 1, 2011; and
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only $50 million of the $300 million may be used to redeem shares of the Dynegy Inc. Series B preferred stock held by ChevronTexaco, and Dynegy Inc. must permanently reduce commitments under the credit facility concurrently by three times the amount used to redeem such shares.
Notwithstanding the foregoing, Dynegy Inc. must have $500 million of liquidity for ten days prior to and as of the date of the repurchase or redemption of our senior notes or the Dynegy Inc. Series B preferred stock.
The financial covenants in the credit facility are described below. Dynegy Inc. and its subsidiaries, including us but excluding IP and DGC and their respective subsidiaries, are prohibited from:
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permitting their Secured Debt/EBITDA Ratio (as defined in the credit facility) from and after September 30, 2003 to be greater than the ratio set forth below:
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the definition of EBITDA in the credit facility specifically excludes, among other items, (i) discontinued business operations (including third-party marketing and trading, communications and tolling arrangements), (ii) disclosed litigation, (iii) extraordinary gains or losses, (iv) any impairment, abandonment, restructuring or similar non-cash expenses, and (v) turbine cancellation payments up to $50 million in the aggregate;
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permitting their liquidity to be less than $200 million for a period of more than ten consecutive business days; or
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making capital expenditures during the four fiscal quarter period ending on the applicable dates set forth below in an amount exceeding the amount set forth opposite such fiscal quarter:
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making capital expenditures in connection with the completion of the Rolling Hills facility in an aggregate amount exceeding $85 million.
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With respect to the quarterly restrictions on capital expenditures set forth above, Dynegy Inc. may (i) carry forward any amount not expended in the four fiscal quarter period in which it was permitted and (ii) carryback up to 50 percent of any amount permitted in a future four fiscal quarter period to any prior four fiscal quarter period and the amount related to the future four fiscal quarter period will be reduced accordingly. Further, Dynegy Inc. and its subsidiaries, including us, may make additional capital expenditures that are required to comply with applicable law.
The credit facility contains events of default relating to:
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non-payment of principal when due, non-payment of interest or any commitment fee within three days or non-payment of any other amounts payable under applicable loan documents within five business days;
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failure to comply with specified covenants and agreements, subject to applicable grace periods;
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incorrect or materially misleading representations or warranties when made;
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specified defaults under (i) any debt or guarantee obligation having an aggregate principal amount in excess of $50 million or (ii) certain swap contracts with a termination value owed to the counterparty in excess of $50 million;
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specified insolvency proceedings that are not discharged or stayed within 60 days or the inability to pay debts as they become due;
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the entry of a final, non-appealable judgment in excess of $50 million (net of insurance) that is not discharged or stayed within 60 days;
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specified ERISA-related events involving in excess of $50 million; and
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any change of control.
Upon the occurrence of any event of default, upon the request of lenders representing more than 50 percent of borrowings outstanding under the credit facility, such lenders may, among other things, declare all borrowings outstanding (including letters of credit) under the credit facility immediately due and payable.
The foregoing description of the material terms of our new credit facility and related ancillary documents is a summary of certain provisions of the definitive agreements governing the credit facility and should be read in conjunction with such agreements, which are included as exhibits to this Form 10-K.
Renaissance and Rolling Hill Credit Facility. In July 2002, we completed a $200 million interim financing, bearing interest at LIBOR plus 1.38 percent. This loan was scheduled to mature in January 2003 and was secured by interests in our Renaissance and Rolling Hills merchant power generation facilities. In January 2003, we repaid $94 million of this facility and refinanced the remaining $106 million. The maturity date on the remaining $106 million was extended to October 15, 2003 and the interest rate on the remaining balance was changed to LIBOR plus five percent. We recently agreed to prepay the remaining $106 million on April 16, 2003.
Interim Financing. In June 2002, we completed a $250 million interim financing, bearing interest at LIBOR plus 1.75 percent. This loan was scheduled to mature in June 2003 and represented an advance on a portion of the proceeds from the sale of our United Kingdom natural gas storage facilities. In September 2002, we sold the entity that owned the Hornsea storage facility and in October 2002 we repaid approximately $189 million of this interim financing with the net proceeds. In November 2002, we sold the entities that owned the Rough facilities and repaid the remaining balance of this financing with a portion of the proceeds therefrom.
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Senior Notes. In July 2002, we repaid our $200 million 6.875% senior notes. On February 21, 2002, we issued $500 million of 8.75% senior notes due 2012. Interest on the notes is due on February 15 and August 15 of each year, beginning August 15, 2002. The notes are unsecured and are not subject to a sinking fund.
ABG Gas Supply Credit Agreement. On April 10, 2001, ABG Gas Supply entered into a credit agreement with a consortium of lenders in order to provide financing associated with Project Alpha. Advances under the agreement allowed ABG Gas Supply to purchase NYMEX natural gas contracts with the underlying physical gas supply to be sold to Dynegy Marketing and Trade under an existing natural gas purchase and sale agreement. The credit agreement requires ABG Gas Supply to repay the advances in monthly installments commencing February 2002 through December 2004 from funds received from Dynegy Marketing and Trade under the natural gas purchase and sale agreement. The advances bear interest at a Eurodollar rate plus a margin as defined in the agreement (2.715% at December 31, 2002). Advances of $259 million and $282 million were outstanding under this agreement at December 31, 2002 and 2001, respectively.
DMG Secured Debt. In June 2000, Dynegy and Black Thunder Investors LLC (“Investor”) invested in Catlin Associates, L.L.C. (“Catlin”), an entity that we consolidated, with the Investor’s ownership in Catlin reflected as minority interest on the consolidated balance sheets at December 31, 2001. We invested $100 million in Catlin and the Investor contributed $850 million. As a result of its investment, the Investor received a preferred interest in Catlin, which holds indirect economic interests in some of our Midwest generation assets, including the coal-fired generation units in Illinois. This preferred interest is a passive interest and generally is not entitled to management rights.
Originally, on or before June 29, 2005, we were effectively obligated to purchase the Investor’s preferred interest for $850 million unless the Investor agreed to extend or refinance this obligation. Alternatively, we could liquidate Catlin’s assets, including DMG’s generating assets, to satisfy this obligation.
We completed an amendment to this transaction in June 2002 that permanently removed a $270 million obligation that could have been triggered by declines in our credit ratings. The amended agreement requires one of our subsidiaries to make periodic payments totaling $275 million over the remaining three years of the transaction with $577 million due in June 2005. At December 31, 2002, this subsidiary had already paid approximately $92 million of this total. Quarterly maturities are approximately $20 million through the first quarter 2005. Balances outstanding incur interest based on market conditions in accordance with the agreement. In addition, we agreed to grant mortgages on the Midwest generation assets covered by the transaction, post a letter of credit to secure a contingent obligation that expired on December 31, 2002 and to make certain structural changes to enhance the security of the third-party lenders involved in the transaction. As a result of this amendment, $796 million related to Catlin was reclassified from minority interest to debt on our consolidated balance sheets.
Generation Facility Debt. We executed lease arrangements for the purpose of constructing two generation facilities located in Georgia and Kentucky. As originally constituted, these arrangements require variable-rate interest only payments that include an option to purchase the related assets at maturity of the facility for a balloon payment equal to the principal balance on the financing. In December 2002, we repaid the principal balance under one of the generation facility lease arrangements. The remaining generation lease arrangement expires in 2007 and bears interest at LIBOR plus 1.5% to 2.5%, depending on the tranche.
Generation Facility Capital Lease. In response to the initiatives currently underway at the FASB, on June 28, 2002, we unilaterally undertook certain actions, the effect of which altered the accounting for one of our existing lease obligations. These actions included the delivery of a guarantee of the lessor debt in the lease of a power generation facility. As a result of these actions, the lease is now accounted for as a capital lease and
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
approximately $165 million of generation assets and the associated debt were brought on-balance sheet. We have the option to purchase the related assets at lease maturity in 2005. This obligation bears interest at a rate of LIBOR plus 1.5% to 2.75%, depending on the tranche.
This non-cash action resulted in an increase to property, plant and equipment and a corresponding increase in long-term debt on our condensed consolidated balance sheets. This obligation was previously disclosed as a lease obligation in the footnotes to our financial statements and in the Commercial Financial Obligations and Contingent Financial Commitments tables in our 2001 Form 10-K as amended.
The following is a schedule of future minimum lease payments under the capital lease together with the present value of the net minimum lease payments as of December 31, 2002 ($ in millions):
Other Obligations. In connection with five fully collateralized generation lease arrangements, we had recorded a construction agency liability as of December 31, 2001. The construction agency liability was included in accrued liabilities and other in the accompanying consolidated balance sheets, and totaled $445 million, at December 31, 2001. The construction agency liability was secured by a note receivable owed to us, which was included in prepayments and other assets on the accompanying consolidated balance sheets at December 31, 2001. During 2002, we terminated the generation lease arrangements. Under the terms of this agreement we received title to the leased assets and assigned the note receivable to the lessor in exchange for forgiveness of the construction agency liability.
We incurred upfront fees aggregating approximately $25 million in connection with the interim financings, Black Thunder amendment and other transactions described above. Such amounts have been capitalized and are amortized over the term of the respective financing transactions.
NOTE 11-RELATED PARTY TRANSACTIONS
Transactions with ChevronTexaco. In March 2002, we agreed with ChevronTexaco to expand our commercial relationships to include substantially all of the natural gas and domestic mixed NGLs and NGL products produced or controlled by the former Texaco.
In August 2002, we executed an agreement with ChevronTexaco pursuant to which the parties amended the existing gas purchase agreement, security agreement, netting agreement and certain related agreements. Under this new agreement, we agreed to accelerate payment to the month of delivery for a portion of the natural gas we purchase from ChevronTexaco, with the amount of the accelerated payment generally being equal to 75 percent of the value of the prior month’s gas deliveries, after reduction pursuant to a netting agreement between us and ChevronTexaco. This payment arrangement was effective upon the closing of the sale of Northern Natural described in Note 3-Dispositions, Discontinued Operations and Acquisitions beginning on page above. The accelerated payment totaled $176 million at December 31, 2002.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Also in August 2002, in partial satisfaction of certain of our obligations to ChevronTexaco under these agreements, we sold to ChevronTexaco our 39.2 percent ownership interest in WTLPS, which is the owner of West Texas LPG Pipeline. ChevronTexaco was already the owner of the largest interest in WTLPS and the operator of the pipeline. The interest sold to ChevronTexaco was valued at $45 million. This non-cash transaction reduced accounts payable to affiliates and unconsolidated investments by $45 million.
In connection with our announced exit from third-party risk management aspects of the marketing and trading business, we have agreed with ChevronTexaco to terminate the natural gas purchase agreement between the parties and to provide for an orderly transition of responsibility for marketing ChevronTexaco’s domestic natural gas production. This agreement will not affect our contractual agreements with ChevronTexaco relative to ChevronTexaco’s U.S. natural gas processing and the marketing of ChevronTexaco’s domestic NGLs. The cancellation of the agreement was effective January 1, 2003. In accordance with the termination of the natural gas purchase agreement, we paid ChevronTexaco $13 million. As part of the transition, we also agreed to provide scheduling, accounting and reporting services to ChevronTexaco through April 2003. We were obligated to purchase any gas not sold under the ChevronTexaco agreements for February and March 2003 at index.
Other transactions with ChevronTexaco Inc. result from purchases and sales of natural gas, NGLs and crude oil between our affiliates and ChevronTexaco. We believe that these transactions are executed at prevailing market rates. During the years ended December 31, 2002, 2001 and 2000, our marketing business recognized net purchases from ChevronTexaco of $1.5 billion, $2.7 billion and $2.1 billion. In accordance with the net presentation provisions of EITF 02-03, 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, 2002, 2001 and 2000, our other businesses recognized aggregate sales to ChevronTexaco of $0.8 billion, $0.9 billion and $1.1 billion and aggregate purchases of $0.5 billion, $0.5 billion and $0.7 billion, which are reflected gross on the consolidated statements of operations.
Equity Investments. We hold investments in joint ventures in which ChevronTexaco or its affiliates are also investors. These investments include a 22.9% ownership interest in Venice Energy Services Company, L.L.C., which holds a pipeline gathering system, a processing plant, a fractionator and an underground NGL storage facility in Louisiana; and a 50% ownership interest in Nevada Cogeneration Associates #2, which holds our Black Mountain power generation facility. During the years ended December 31, 2002, 2001 and 2000, our portion of the net income from joint ventures with ChevronTexaco was approximately $17 million, $14 million and $17 million, respectively.
We also purchase and sell natural gas, NGLs, crude oil and power and, in some instances, earn management fees from certain entities in which we have equity investments. During the years ended December 31, 2002, 2001 and 2000, our marketing business recognized net sales to affiliates related to these transactions of $1.0 billion, $1.8 billion and $0.7 billion. In accordance with the net presentation provisions of EITF 02-03, 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, 2002, 2001 and 2000, our other businesses recognized aggregate sales to these affiliates of $15 million, $19 million and $16 million and aggregate purchases of $152 million, $185 million and $130 million, which are reflected gross on the consolidated statements of operations. Revenues were related to the supply of fuel for use at generation facilities, primarily West Cost Power, and the supply of natural gas sold by retail affiliates. Expenses primarily represent the purchase of NGLs that are subsequently sold in our marketing operations.
Also during 2001, we earned approximately $8 million of interest income related to cash loaned to West Coast Power. The loan was created as a result of natural gas fuel costs owed by West Coast Power to one of our subsidiaries. As of December 31, 2001, West Coast Power had repaid in full all amounts owed to us. We have
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
guaranteed $13 million of estimated environmental obligations and possible forfeiture of our rights to dividends previously received if collateral requirements under the agreement are not met. At December 31, 2002, the maximum exposure under the guarantee is $16 million.
At December 31, 2002, we had two financing arrangements, which originated during 2001, under which we were owed an aggregate of approximately $12 million from one of our equity investees, Nicor Energy, L.L.C. Under a gas purchase agreement, Nicor was obligated to purchase a total of 3.5 million MMBtu over the fifteen-month period October 2001 through December 2002 at a contract price of $18 million. Approximately $4 million of the $18 million per the agreement was outstanding at December 31, 2002. Additionally, under a loan agreement, which bears interest at a rate of prime plus two percent, we advanced $8.2 million to Nicor to satisfy a third-party debt all of which was outstanding at December 31, 2002. During the first quarter of 2003, substantially all of the operations of Nicor Energy have been sold and we expect to liquidate the company in the second quarter of 2003. We anticipate that all amounts due to us from Nicor Energy will be repaid with the proceeds of this liquidation.
Other. We routinely conduct business with subsidiaries of Dynegy Inc. that are not a part of this consolidated group. As a result of such transactions, we have an approximate $86,000 and $2.9 million accounts payable, affiliates balance as of December 31, 2002 and 2001, respectively.
Additionally, certain of our subsidiaries received revenues of approximately $486 million, $459 million and $557 million from IP during the years ended December 31, 2002, 2001 and 2000, respectively. These revenues relate to a PPA that we have with IP that provides IP the right to purchase power from us for a primary term extending through December 31, 2004. The primary term may be extended on an annual basis, subject to concurrence by both parties. The PPA defines the terms and conditions under which we provide power and energy to IP using a tiered pricing structure. The agreement requires IP to compensate us for capacity charges through 2004 at a total contract cost of $639.6 million. According to the PPA agreement, IP is to provide a security guarantee of $50 million upon a credit downgrade event. This guarantee is being fulfilled by a $50 million guarantee from Dynegy Inc. on IP’s behalf. The PPA obligates us to provide power up to the reservation amount even if we have individual units unavailable at various times.
The subsidiaries also purchased approximately $10 million, $10 million and $11 million of natural gas from IP during the years ended December 31, 2002, 2001 and 2000, respectively.
NOTE 12-INCOME TAXES
We are subject to U.S. federal, foreign and state income taxes on our operations. Components of income tax expense (benefit) related to income (loss) from continuing operations were ($ in millions):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Components of income (loss) from continuing operations before income taxes were as follows ($ in millions):
Deferred income taxes are provided for the temporary differences between the tax basis of our assets and liabilities and their reported financial statement amounts. Significant components of deferred tax liabilities and assets were ($ in millions):
Realization of the aggregate deferred tax asset is dependent on our ability to generate taxable earnings and regular tax in excess of tentative minimum tax in the future. At December 31, 2002, the valuation allowance of $5 million relates to foreign tax credit carryforwards which management believes are not more likely than not to be fully realized in the future based on our ability to generate foreign income. There was no valuation allowance established at December 31, 2002 for net operating loss carryforwards, as management believes the net operating loss carryforwards are more likely than not to be fully realized in the future based on managements estimates of future net income and related taxes.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Income tax provisions on continuing operations for the years ended December 31, 2002, 2001 and 2000, were equivalent to effective rates of 22 percent, 43 percent and 35 percent, respectively. Differences between taxes computed at the U.S. federal statutory rate and our reported income tax provision were ($ in millions):
At December 31, 2002, we had approximately $143 million of regular federal tax net operating loss carryforwards, $28 million of AMT credit carryforwards and $971 million of AMT net operating loss carryforwards after considering the effects of carrybacks to prior years. The federal net operating loss carryforwards expire from 2009 through 2022. The AMT credit carryforwards do not expire. Certain provisions of the Internal Revenue Code place an annual limitation on our ability to utilize tax carryforwards existing as of the date of a 1995 and a 2000 business acquisition. These are not expected to have an impact on our overall ability to utilize such tax carryforwards. State net operating loss carryforwards in states where we file unitary state income tax returns are $13 million in California, $41 million in Illinois and $5 million in New Mexico. These state net operating loss carryforwards expire in 2012, 2022 and 2007, respectively. We believe such carryforwards will be fully realized prior to expiration.
Based on 2002 operating results, we have generated a significant current tax net operating loss that is available for carryback or carryforward to reclaim certain U.S. federal income taxes paid in prior years. Accordingly, Dynegy Inc. received a tax refund in the first quarter of 2003 of approximately $110 million for U.S. federal income taxes paid in 2001 and 2000 as a result of such carryback of tax losses.
We plan to reinvest the earnings of foreign subsidiaries indefinitely and no U.S. taxes or foreign withholding taxes were provided on these earnings in 2002, 2001 or 2000. It is not practicable to estimate the amount of unrecognized U.S. deferred taxes or foreign withholding taxes, if any, that might be payable on the actual or deemed remittance of such earnings. As of December 31, 2002, we have no material undistributed earnings of foreign subsidiaries.
As more fully discussed in Note 19-Quarterly Financial Information (Unaudited) beginning on page, we entered into the Project Alpha structured natural gas transaction in April 2001. Dynegy Inc. has not recognized the permanent tax benefit related to Project Alpha in its 2002 or 2001 U.S. consolidated federal income tax return or financial statements.
Contingent Liability Transactions. We entered into three contingent liability transactions in 1996, 1997 and 1999. These transactions involved the transfer of an aggregate of $182 million in contingent liabilities primarily assumed by us in prior acquisitions of three separate companies. The three companies to which these contingent liabilities were transferred subsequently sold preferred or restricted common stock to various purchasers. Two of the companies sold stock to an aggregate of 15 non-executive Dynegy employees with positions of influence over the contingent liabilities held in such companies; the purchaser of the stock of the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
third company is an unaffiliated third party. The stock purchased by these non-executive employees was later redeemed under the terms of the applicable purchase agreements. The average redemption prices and dividends paid to these present and former employees, which related to their successful management of the subject contingent liabilities and exceeded the amounts paid by such employees for the stock they acquired, was $62,000 and no such employee received more than $81,000.
On January 18, 2001, the IRS issued Notice 2001-17 in which it identified these types of transactions as “listed transactions or tax shelters.” Pursuant to a settlement initiative described in IRS Revenue Procedure 2002-67, Dynegy Inc. is currently resolving with the IRS any issues in dispute related to these liability management companies. We expect that the settlement will have no material impact on our financial statements.
NOTE 13-REDEEMABLE PREFERRED SECURITIES
In May 1997, NGC Corporation Capital Trust I (“Trust”) issued, in a private transaction, $200 million aggregate liquidation amount of 8.316% 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 our 8.316% 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 our option, in whole at any time or in part from time to time, at formula-based redemption prices, as defined in the indenture. The Subordinated Debentures represent our unsecured obligations and rank subordinate and junior in right of payment to all of our 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, as described in the indenture. We may defer payment of interest on the subordinated debentures as described in the indenture.
NOTE 14-COMMITMENTS AND CONTINGENCIES
Legal Proceedings. Set forth below is a description of our material legal proceedings. In addition to the matters described below, we are party to legal proceedings arising in the ordinary course of business. In the opinion of management, the disposition of these ordinary course matters will not have a material adverse effect on our financial condition, results of operations or cash flows.
We record reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable in accordance with SFAS No. 5, “Accounting for Contingencies.” For environmental matters, we record liabilities when environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Please read Note 2-Accounting Policies, beginning on page, for further discussion.
With respect to several of the items listed below, we have determined that a loss is not probable or that any such loss, to the extent probable, is not reasonably estimable. Notwithstanding the foregoing, our management has assessed the matters described below based on currently available information and made an informed judgment concerning the likely outcome of such matters, 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, as a result of facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.
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Shareholder Litigation. Since April 2002, a number of class action lawsuits have been filed on behalf of purchasers of Dynegy Inc.’s publicly traded securities generally during the period between April 2001 and April 2002. These lawsuits principally assert that Dynegy Inc. and certain of its executive officers violated the federal securities laws in connection with our accounting treatment and disclosure of Project Alpha. These lawsuits have been consolidated in the United States District Court for the Southern District of Texas. On October 28, 2002, the court in which the cases have been consolidated appointed the Regents of the University of California as lead plaintiff and the law firm of Milberg Weiss as class counsel. Plaintiffs have until June 6, 2003 to file a consolidated amended complaint, which may differ materially from the complaints presently on file. We expect that the amended complaint will include additional allegations relating to Project Alpha, particularly in light of the SEC settlement described below, as well as allegations relating to round-trip trading, the submission of false trade reports to publications that calculate natural gas index prices, alleged manipulation of the California power market and the restatement of Dynegy Inc.’s financial statements for periods since 1999. The original complaint covered a class period from April 2001 to April 2002. We expect the amended complaint to cover a longer period, particularly in light of these previously announced restatements. It is not possible to predict with certainty whether we will incur any liability or to estimate the damages, if any, that might be incurred in connection with these lawsuits. An adverse result could have a material adverse effect on our financial condition and results of operations.
In addition, three derivative lawsuits have been filed in which Dynegy Inc. is a nominal defendant. The lawsuits relate to Project Alpha, round-trip trades and alleged manipulation of the California power market. The lawsuits seek recovery on behalf of Dynegy Inc. from various present and former officers and directors. Because of the nature of these derivative lawsuits, we do not expect to incur any material liability with respect to these derivative claims.
ERISA/401(k) Litigation. On August 15, 2002, a purported class action complaint was filed against Dynegy Inc. in the United States District Court for the Southern District of Texas (Houston Division) alleging violations of the Employee Retirement Income Securities Act. The lawsuit concerns the Dynegy Inc. 401(k) Savings Plan and claims that its Board of Directors and certain former and current officers involved in the administration of the 401(k) Plan breached their fiduciary duties to the Plan’s participants and beneficiaries in connection with the Plan’s holdings of Dynegy Inc. common stock. The lawsuit seeks unspecified damages for the losses to the Plan resulting from the alleged breaches of fiduciary duties, as well as attorney’s fees and certain other costs. The putative class was defined as participants holding Dynegy Inc. common stock in the plan as of April 17, 2001 or later. On February 12, 2003, the plaintiffs filed an amended complaint, which extended the putative class period back to April 27, 1999. Additional past Board members were named as defendants, as were past and present members of Dynegy Inc.’s Benefit Plans Committee. The amended complaint alleges that Dynegy Inc.’s earnings and business conditions were misstated from 1999 forward and that, during such period, Dynegy Inc. and members of the Board, including members of the Compensation and Human Resources Committee of the Board, breached fiduciary duties by failing to disclose to the Benefit Plans Committee information regarding risks associated with its business due to misstatements about revenues, earnings and operations, which information was material to the appropriateness of Dynegy Inc. common stock as an investment option, and by failing to monitor the Benefit Plans Committee. The amended complaint further alleges that the Benefit Plans Committee breached fiduciary duties by failing to disclose complete and accurate information with respect to the suitability of investing in Dynegy Inc. common stock and by failing to eliminate Dynegy Inc. common stock as a Plan investment option, and that the Benefit Plans Committee breached their duty of loyalty to discharge their duties to the Plan solely in the interest of the participants and beneficiaries. The amended complaint also alleges that we breached co-fiduciary duties under ERISA and, to the extent it is found not to be a fiduciary, that we benefited by knowingly participating in fiduciary breaches by others. The plaintiff filed a second amended complaint on April 7, 2003, which names additional defendants certain former employees who served on a predecessor committee to the Benefit Plans Committee. The plaintiff also included in
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this second amended complaint allegations relating to Project Alpha, round trip trades and the gas price index investigation.
Dynegy Inc. has stated that it is analyzing these claims and intends to defend against them vigorously. As with the shareholder class action lawsuits described above, it is not possible to predict with certainty whether we will incur any liability or to estimate the damages, if any, that might be incurred in connection with this lawsuit. However, an adverse outcome could have a material adverse effect on our financial condition and results of operations.
Baldwin Station Litigation. IP and Dynegy Midwest Generation, Inc., collectively referred to in this section as the Defendants, are currently the subject of a Notice of Violation (NOV) from the EPA and a complaint filed by the EPA and the Department of Justice alleging violations of the Clean Air Act, the regulations promulgated thereunder and certain Illinois regulations adopted pursuant to the Clean Air Act. Eight similar notices and complaints were filed against other owners of coal-fired power plants. Both the NOV and the complaint allege that certain equipment repairs, replacements and maintenance activities at the Defendants’ three Baldwin Station generating units constituted “major modifications” under the Prevention of Significant Deterioration (PSD), the New Source Performance Standard (NSPS) regulations and the applicable Illinois regulations, and that the Defendants failed to obtain required operating permits under the applicable Illinois regulations. When activities that meet the definition of “major modifications” occur and are not otherwise exempt, the Clean Air Act and related regulations generally require that the generating facilities at which such activities occur meet more stringent emissions standards, which may entail the installation of potentially costly pollution control equipment. The Defendants filed an answer denying all claims and asserting various specific defenses, and a trial date of June 3, 2003 has been set.
We have undertaken activities to significantly reduce emissions at the Baldwin Station since the complaint was filed in 1999. In 2000, the Baldwin Station was converted from high to low sulfur coal, resulting in sulfur dioxide emission reductions of over 90% from 1999 levels. Furthermore, selective catalytic reduction equipment has been installed at two of the three units at Baldwin Station, resulting in significant emission reductions of nitrogen oxides. However, the EPA may seek to require the installation of the “best available control technology,” or the equivalent, at the Baldwin Station. Independent experts hired by us estimated that capital expenditures of up to $410 million could be incurred if the installation of best available control technology were required. The EPA also has the authority to seek penalties for the alleged violations at the rate of up to $27,500 per day for each violation.
On February 19, 2003, the Court granted our motion for partial summary judgment based on the five-year statute of limitations. As a result, the EPA will not be permitted to seek any monetary civil penalties for claims related to construction without a permit under the PSD regulations. The Court’s ruling also precludes monetary civil penalties for a portion of the claims under the NSPS regulations and the applicable Illinois regulations. We believe that we have meritorious defense against the remaining claims and will vigorously defend against them. We have recorded a reserve for potential penalties that could be imposed if the EPA were to prosecute successfully its remaining claims for penalties. We have agreed to defend IP in the NOV and complaint and will bear all costs and expenses in connection with such defense, and any fines, penalties and similar monetary charges that may be incurred in connection with any judgment rendered in or any settlement of the NOV or complaint.
None of the Defendants’ other facilities are covered in the complaint and NOV, but the EPA has officially requested information, and we have provided such information, concerning activities at the Defendants’ Vermilion, Wood River and Hennepin Plants as well as the Danskammer and Roseton plants operated by other Dynegy subsidiaries. The EPA could eventually commence enforcement actions based on activities at these plants.
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California Market Litigation. Six class action lawsuits were filed in 2000-2001 against various Dynegy entities based on the events occurring in the California power market. The complaints allege violations of California’s Business and Professions Code, Unfair Trade Practices Act and other related statutes. The plaintiffs allege that the defendants, including the owners of in-state generation and various power marketers, conspired to manipulate the California wholesale power market to the detriment of California consumers. Included among the acts forming the basis of the plaintiffs’ claims are the alleged improper sharing of generation outage data, improper withholding of generation capacity and the manipulation of power market bid practices. The plaintiffs seek unspecified treble damages.
All six lawsuits were consolidated before Judge Sammartino, Superior Court Judge for the County of San Diego. Subsequent to this consolidation, two of the defendants filed cross-complaints against a number of corporations and governmental agencies that sold power in California’s wholesale energy markets. Four cross- defendants removed the six cases to the United States District Court for the Southern District of California (San Diego) and the cases were returned to Multi-District Litigation Proceeding 1405, referred to as the California Wholesale Electricity Antitrust Litigation. The original plaintiffs in the six consolidated complaints filed motions to remand the consolidated cases back to state court, which motions were granted. Some of the cross-defendants then appealed that ruling and, prior to the remand taking effect, the Ninth Circuit Court of Appeals granted review and stayed the remand order. A ruling by the Ninth Circuit is not expected until late this year at the earliest.
On January 6, 2003, the Federal Judge in the California Wholesale Electricity Antitrust Litigation dismissed with prejudice one of the cases, Public Utility District No. 1 of Snohomish County, based upon the filed rate doctrine and federal preemption principles. On January 27, 2003, the plaintiffs in that case filed a notice of appeal of the Court’s decision.
In addition to the six consolidated lawsuits discussed above, ten other putative class actions and/or representative actions have been filed on behalf of business and residential electricity consumers. The lawsuits were filed in various state courts and in the United States District Court for the Northern District of California. The defendants named in these lawsuits are various power generators and marketers, including Dynegy and some of our affiliates. The complaints allege unfair, unlawful and deceptive practices in violation of the California Unfair Business Practices Act and seek to enjoin illegal conduct, restitution and unspecified damages. While some of the allegations in these lawsuits are similar to the allegations in the other six lawsuits, these lawsuits include additional allegations based on events occurring subsequent to the filing of the other six lawsuits. These additional allegations include allegations similar to those made by the California Attorney General in the March 11, 2002 lawsuit described below as well as allegations that contracts between these power generators and the CDWR constitute unfair business practices resulting from market manipulation. The lawsuits filed in state court were removed to federal courts and ultimately all of these cases have been added to the California Wholesale Electricity Antitrust Litigation. The plaintiffs in all but one of these cases have filed motions to remand the cases to state court. The oral argument on these motions to remand was heard on March 26, 2003 before Judge Whaley, and the matters are currently under submission.
Two other actions have recently been filed with allegations similar to those in the California Wholesale Electricity Antitrust Litigation on behalf of residents of the State of Washington and residents of the State of Oregon. Symonds v. Dynegy was filed in the United States District Court for the Western District of Washington. Lodewick v. Dynegy was originally filed in the State Court of Oregon and has since been removed to the United States District Court for the District of Oregon. Defendants in these matters sought to have these actions included in the California Wholesale Electricity Antitrust Litigation; however, the Multi-District Litigation panel indicated that since Judge Whaley was a resident of the State of Washington, it is unlikely that the cases would be assigned
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to the California Wholesale Electricity Antitrust Litigation. A motion by some of the defendants has been filed with the Multi-District Litigation panel seeking to have the assignment of these two cases to the Honorable Vaughn Walker in the Northern District of California, who has pending before him those cases filed by the California Attorney General as referred to below.
On March 11, 2002, the California Attorney General filed, on behalf of the People of the State of California, complaints in San Francisco Superior Court against several owners of power generation facilities, including subsidiaries of West Coast Power. The complaints allege that since June 1998, these power generators sold power in the open market that should have been held in emergency reserve for the State. In the aggregate, the complaints seek more than $150 million in penalties, restitution and return of profits from the generators. These lawsuits were subsequently removed to the United States District Court for the Northern District of California. The California Attorney General filed motions to remand the cases back to state court. By Order issued on August 6, 2002, Judge Walker denied the motions to remand, thus keeping the cases in federal court. On March 25, 2003, Judge Walker dismissed this order based upon the filed rate doctrine and federal preemption principles. The California Attorney General has appealed this decision and is seeking an expedited briefing schedule.
On November 20, 2002, a new class action was filed in the Superior Court of the State of California for the County of Los Angeles styled Cruz Bustamante v. The McGraw Hill Companies, Inc., et al. on behalf of purchasers of natural gas and electricity in the State of California. Plaintiffs allege damages as the result of the defendants’ alleged false reporting of pricing and volume information regarding natural gas transactions. Pursuant to a stipulation of the parties, the Court has issued a briefing schedule for defendants’ responsive pleadings in this action. The Court has ordered that the hearing on any such motions will be held on June 18, 2003.
We believe that we have meritorious defenses to these claims and intend to vigorously defend against them. We are unable to estimate the range of possible loss that could be incurred with respect to these lawsuits. However, an adverse result in any of these proceedings could have a material adverse effect on our financial condition and results of operations.
FERC and Related Regulatory Investigations.
Requests for Refunds. On July 25, 2002, the FERC initiated a hearing to establish refunds to electricity customers, or offsets against amounts owed to electricity suppliers, during the period of October 2, 2000 through June 19, 2001. In particular, the FERC established a methodology to calculate mitigated market clearing prices in the Cal ISO and the Cal PX markets. During March 2002 and August 2002, hearings on this matter were held before an administrative law judge. On December 12, 2002, the administrative law judge issued his recommendations regarding the appropriate level of refunds or offsets. Those recommendations, however, do not fully reflect proposed refund or offset amounts for individual companies. In order to determine such amounts, the Cal ISO and Cal PX must rerun their settlement processes in a compliance stage of the proceeding. We subsequently filed briefs with the FERC supporting certain aspects of the administrative law judge’s decision and opposing others. The matter now is awaiting a decision from the FERC.
In August 2002, the FERC requested comments on a proposal made by the FERC staff to change the method for determining natural gas prices for purposes of computing the mitigated market-clearing price that it intends to utilize in calculating refunds for sales of power in California power markets during the period from October 2, 2000 to June 19, 2001. The proposal replaces the gas prices used in the computation, thus reducing the mitigated market clearing price for power and increasing calculated refunds, subject to a provision that generally would provide full recoverability of gas costs paid by the generators to unaffiliated third parties. This proposal was adopted by the FERC on March 26, 2003. We expect that proceedings at FERC to determine final calculated refund amounts, net of any adjustments for actual gas costs incurred by generators, will commence during the second quarter 2003.
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On March 27, 2003, the FERC issued a decision in the refund case in which it essentially adopted the FERC staff’s proposal to change the gas pricing component of the refund calculations. The FERC did, however, recognize that many generators paid higher prices for gas than would be reflected in this new calculation and provided a mechanism whereby generators can submit evidence of their actual out-of-pocket spot gas purchase costs and have those costs deducted from the refund calculations. We intend to vigorously pursue relief under this procedure. The FERC otherwise affirmed the decision by the administrative law judge, and indicated that it expected to have specific refund or offset calculations by the end of the Summer 2003. We intend to seek rehearing of the FERC’s decision changing the gas pricing methodology.
On November 20, 2002, the FERC granted a motion filed jointly by the People of the State of California, ex rel. Bill Lockyer, Attorney General, the California Electricity Oversight Board, the Public Utilities Commission of the State of California, Pacific Gas and Electric Company, and Southern California Edison Company, referred to in this section as the California Parties, to reopen the record in the refund proceeding to allow 100 days of discovery into allegations of market manipulation. The California Parties submitted the results of their discovery effort on March 3, 2003. Other parties also made such submissions. The California Parties sought increased refunds for the period from October 2, 2000 to June 19, 2001 based on, among other things, the adoption of the FERC staff’s proposal to change the gas prices used in computing refunds. The California Parties also sought refunds for the period from May 1, 2000 through October 1, 2000. We submitted our response on March 20, 2003. We believe that we have meritorious defenses against these claims and intend to vigorously defend against them. Please read “-West Coast Power” beginning on page below for a discussion of the reserves recorded by West Coast Power relative to its exposure in the California power market.
Other FERC and California Investigations. On February 13, 2002, the FERC initiated an investigation of possible manipulation of natural gas and power prices in the western United States during the period from January 2001 through the present. On May 8, 2002, in response to three memoranda discovered by the FERC allegedly containing evidence of market manipulation in California, the FERC issued requests for information to all sellers in the Cal ISO and Cal PX markets during 2000 and 2001 seeking information with respect to whether those sellers engaged in trading strategies described in the three memoranda. We responded to these requests, indicating that we did not engage in the trading strategies described in the three memoranda. In August 2002, the FERC staff issued its preliminary report on its investigation into trading practices in the three memoranda. We continued to provide FERC with additional information relevant to its investigation.
On March 26, 2003, the FERC staff issued its Final Report on Price Manipulation in Western Markets, addressing a number of issues. In its report, the FERC staff indicated that it appears a majority of public utility entities, and some non-public utilities, engaged in some of the above-referenced trading strategies during the two-year review period. The FERC staff also recommended that the FERC issue orders requiring that Dynegy and 36 other market participants be required to “show cause” why their activities did not violate the Cal ISO and Cal PX tariffs. Potential penalties for violation of the tariff could include disgorgement of unjust profits from activities found to be in violation of the tariff. Many of these allegations have already been raised and were answered in large part in our FERC filing of March 20, 2003. We intend to defend against them vigorously.
On May 21, 2002, the FERC issued requests for information to all sellers of wholesale electricity or ancillary services in the Western Electricity Coordinating Council (“WECC”) and, on May 22, 2002, the FERC issued requests for information to all sellers of natural gas in the WECC or Texas, seeking information with respect to whether those sellers engaged in “wash,” “round-trip” or “sale/buyback” transactions during 2000-2001.
We responded to each of these requests. Based on our investigation to date, we believe that our trading practices are consistent with applicable law and tariffs. We will continue to cooperate fully with these
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investigations. Please read “-SEC Settlement” below for a discussion of our round-trip energy trades with CMS Energy.
On August 13, 2002, the FERC staff issued its preliminary report on its investigation into “wash,” “round-trip” or “sale/buyback” transactions. In the FERC staff’s March 26, 2003 Final Report on Price Manipulation in Western Markets, it recommended that the FERC establish specific rules banning any form of prearranged wash trading activities, but made no recommendations regarding “wash” transactions specifically with respect to us.
Requests for similar information regarding the above-referenced trading strategies and wash trades with respect to electric power trading activities within the ERCOT were received from the Texas Public Utility Commission (“Texas PUC”) in June 2002. We responded to each of these requests. Based on our investigation to date, we believe that our trading practices are consistent with applicable law and tariffs. The Texas PUC has not issued findings on its investigation and we cannot predict with certainty how the investigation will be resolved.
On September 17, 2002, California Public Utilities Commission President Loretta Lynch released a report indicating that Dynegy and five other energy firms did not produce all available power on days in which the State of California experienced power service interruptions between November 1, 2000 and May 31, 2001. No mention is made of prosecuting the named firms in the report. However, the SEC and FERC have requested additional information and comment with respect to the report. On March 26, 2003, the FERC staff issued its analysis of the report and found that it was incomplete and overstated the amount of power withheld. The FERC staff’s analysis further stated that there was no evidence that we withheld any material amounts of power or that we were responsible for any service interruptions.
Trade Press. In September 2002, the FERC staff issued requests for information on issues related to reporting of information on natural gas and electricity trades to energy industry publications that compile and report index prices. We responded to these requests and cooperated with the FERC staff in connection with this matter. In its Final Report on Price Manipulation in Western Markets, the FERC staff made several recommendations in order to ensure the integrity and accuracy of energy price indices in the future. The staff also recommended that the FERC issue orders requiring Dynegy and ten other companies to show cause that employees involved in improper index reporting have been disciplined; that a clear code of conduct is in place for reporting price information; that all trade data reporting is done by an entity within the company that does not have a financial interest in the published index; and that the company is fully cooperating with any government agency investigating its past price reporting. We believe that we are in compliance with each of these recommended requirements.
Western Long-Term Contract Complaints. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints with the FERC asking that it void or reform power supply contracts between the CDWR and, among others, West Coast Power. The complaints allege that prices under the contracts exceed just and reasonable prices permitted under the Federal Power Act. The FERC set these complaints for evidentiary hearing. On January 10, 2003, the FERC granted a motion by Dynegy and other defendants for the administrative law judge to issue a partial initial decision on certain threshold legal issues, and for the FERC itself to resolve the issues on the basis of the record developed at hearing. On January 16, 2003, the administrative law judge issued a decision adopting our view on the threshhold legal issue. The complainants have appealed that decision to the FERC. Both sides of the case also have filed briefs before the FERC and the case is awaiting decision. Additionally, on March 3, 2003, the complainants filed supplemental testimony requesting that the FERC void or reform the power supply contracts at issue based on the allegations of market manipulation submitted by the California Parties. On March 20, 2003, Dynegy and other the defendants filed responses to this submission. While we believe the terms of our contracts are just and reasonable and do not reflect alleged market manipulation, we cannot predict the outcome of this matter.
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In a related complaint, The Kroger Co. filed a complaint with the FERC in August 2002 asking that the four wholesale contracts between Dynegy Power Marketing, Inc. and AES New Energy, Inc., which provides retail service to The Kroger Co., be declared void for their remaining terms, and that the FERC set just and reasonable rates for prior periods. Alternatively, The Kroger Co. asks that the FERC allow for an annual review procedure to reset the contract prices. The complaint alleges that but for the dysfunctional California electricity markets, it would not have entered into the contracts for delivery of energy through December 2006. On March 14, 2003, the FERC issued an order setting The Kroger Co.’s complaint for hearing, establishing hearing procedures and holding the hearing in abeyance pending proceedings for a FERC settlement judge. Settlement proceedings are currently being conducted by the settlement judge. We believe that we have meritorious defenses against these claims and intend to vigorously defend against them.
West Coast Power. Through our interest in West Coast Power, we have credit exposure for past transactions to the Cal ISO and Cal PX, which primarily relied on cash payments from California utilities to in-turn pay their bills. West Coast Power currently sells directly to the CDWR pursuant to a long-term sales agreement. Please see “Western Long-Term Contracts Complaints” above for discussion of the actions taken by various parties with respect to this agreement.
At December 31, 2002, our portion of the receivables owed to West Coast Power by the Cal ISO and Cal PX approximated $200 million. Management is continually assessing our exposure, as well as our exposure through West Coast Power, relative to our California receivables and establishes and maintains reserves as necessary. During 2002, 2001 and 2000, our share of reserves taken by West Coast Power totalled $49.0 million, $122.5 million and $24.5 million, respectively. Our share of the total reserve at December 31, 2002 and 2001 was $200.8 million and $151.8 million, respectively.
Enron Merger Termination Litigation. We and Dynegy Inc. were sued on December 2, 2001 by Enron and Enron Transportation Services Co. in the United States Bankruptcy Court for the Southern District of New York, Adversary Proceeding No. 01-03626 (AJG). Enron claimed that Dynegy Inc. materially breached the Merger Agreement dated November 9, 2001 between Enron and Dynegy Inc. and related entities by wrongfully terminating that Agreement on November 28, 2001. Enron also claimed that we wrongfully exercised our option to take ownership of Northern Natural under an Option Agreement dated November 9, 2001. Enron sought damages in excess of $10 billion and declaratory relief against Dynegy Inc. for breach of the Merger Agreement. Enron also sought unspecified damages against Dynegy Inc. and us for breach of the Option Agreement. We and Dynegy Inc. filed an answer on February 4, 2002, denying all material allegations. On April 12, 2002, the Bankruptcy Court granted our motion to transfer venue in the proceeding to the United States District Court for the Southern District of Texas (Houston Division).
On August 15, 2002, we and Dynegy Inc. entered into an agreement with Enron to settle this lawsuit. Under the terms of the settlement agreement, we and Dynegy Inc. agreed to pay Enron $25 million, $10 million of which was paid to Enron upon approval of the settlement agreement by the Bankruptcy Court, with the remaining $15 million escrowed until approval of the settlement becomes final. In addition, we and Dynegy, Inc. agreed with Enron to exchange mutual releases of any and all claims related to the terminated merger and to dismiss the related litigation. We and Dynegy Inc. also agreed not to pursue any claims for working capital adjustments relating to the acquisition of Northern Natural. The terms of the settlement were approved by the Bankruptcy Court on August 29, 2002. On September 6, 2002, an appeal of the Bankruptcy Court’s approval was filed by the plaintiffs who had filed the class action lawsuits described below.
On February 6, 2003, the District Court affirmed Judge Gonzalez’s order approving the settlement agreement. On April 7, 2003, following the expiration of the time period during which these plaintiffs could have filed a further appeal, we, Dynegy Inc. and Enron filed with the United States District Court for the Southern
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District of Texas (Houston Division) a joint motion for dismissal of Enron’s claims with prejudice. Upon the court’s approval of such motion, our settlement with Enron will be effective and their lawsuit will be formally dismissed.
Ann C. Pearl and Joel Getzler filed a suit against Dynegy Inc. and us in the United States District Court for the Southern District of New York. Plaintiffs filed the lawsuit as a purported class action on behalf of all persons or entities that owned Enron common stock as of November 28, 2001. A similar suit was filed by Bernard D. Shapiro and Peter Strub in the 129th Judicial District Court for Harris County, Texas. Plaintiffs in each case alleged that they are intended third-party beneficiaries of the Merger Agreement dated November 9, 2001 among Enron, Dynegy Inc. and related entities. Plaintiffs claimed that we materially breached the Merger Agreement by, among other things, wrongfully terminating that agreement. Plaintiffs also claimed that we breached the implied covenant of good faith and fair dealing. Plaintiffs sought unspecified damages and other relief. Enron moved for an order of the Bankruptcy Court in the Southern District of New York directing that the Pearl and Shapiro plaintiffs be enjoined from prosecuting their actions and that their actions be immediately dismissed. The Bankruptcy Court held that the claims asserted by the Pearl and Shapiro plaintiffs were the exclusive property of the Enron bankruptcy estate and that the plaintiffs lacked standing to sue as third-party beneficiaries of the Merger Agreement. Accordingly, by an order entered on April 19, 2002, the Bankruptcy Court granted Enron’s motion, enjoined the prosecution of both actions and directed that they be dismissed. The Pearl and Shapiro plaintiffs thereafter complied with that order, but filed an appeal to the United States District Court for the Southern District of New York. On October 22, 2002, the District Court reversed the Bankruptcy Court’s determination, holding that the Pearl and Shapiro plaintiffs do have standing to sue as third-party beneficiaries, and that their claims are not the exclusive property of the bankruptcy estate. Shortly after this ruling, certain Enron shareholders filed an action against Dynegy Inc. for wrongful termination of the Merger Agreement in the United States District Court for the Southern District of New York.
On October 28, 2002, we and Dynegy Inc. filed a declaratory action in Harris County Judicial District Court relating to the Shapiro action. The action seeks to reinstate the Shapiro action in the 129th Judicial District Court that is no longer stayed. The action also seeks affirmative declarations to the effect that Dynegy Inc. did not wrongfully terminate the Merger Agreement, that the termination did not breach any duty owed to the Shapiro plaintiffs or to Enron’s shareholders generally and that neither the Shapiro plaintiffs nor Enron’s shareholders generally have a right to enforce or to make claims under the Merger Agreement.
On April 9, 2003, we and Dynegy Inc. executed a settlement agreement with the former Enron stockholder plaintiffs relating to the purported class action lawsuits described above. Pursuant to the settlement agreement, which is subject to court approval, we and Dynegy Inc. agreed to pay $6 million to settle the claims asserted on behalf of the class of all Enron shareholders who held Enron stock at the time the merger was terminated. We and Dynegy Inc. have a unilateral right to terminate the settlement agreement if any class members opt out of the settlement class or if the court fails to approve any material provision of the settlement agreement.
We believe that we have meritorious defenses against these claims and, subject to the finalization of the settlements described above, intend to vigorously defend against them. An adverse result in any of these proceedings, however, could have a material adverse effect on our financial position and results of operations.
Enron Trade Credit Litigation. As a result of Enron’s bankruptcy filing, we recognized in our fourth quarter 2001 financial statements a pre-tax charge related to our net exposure for commercial transactions with Enron. As of December 31, 2002 our net exposure to Enron, inclusive of certain liquidated damages and other amounts relating to the termination of the transactions, was approximately $84 million and was calculated by setting off approximately $230 million owed from various Dynegy entities to various Enron entities against approximately $314 million owed from various Enron entities to various Dynegy entities. The master netting agreement between us and Enron and the valuation of the commercial transactions covered by the agreement, which valuation is based principally on the parties’ assessment of market prices for such period, remain subject
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to dispute by Enron with respect to which there have been negotiations between the parties. These negotiations have focused on the scope of the transactions covered by the master netting agreement and the parties’ valuations of those transactions. If any disputes cannot be resolved by the parties, the agreements call for arbitration. We have instituted arbitration proceedings against those Enron parties not in bankruptcy and have filed a motion with the Bankruptcy Court requesting that we be allowed to proceed to arbitration against those Enron parties that are in bankruptcy. The Enron parties have responded by opposing our request to enforce the arbitration requirement and filing an adversary proceeding against us. Both the opposition to the arbitration request and the adversary proceeding allege that the master netting agreement should not be enforced and that the Enron companies should recover approximately $230 million from us. We have disputed such allegations and are vigorously defending our position regarding the setoff rights provided for in the master netting agreement. No ruling has been made by the Bankruptcy Court, and the Court has referred the disputes to non-binding mediation. If the setoff rights were modified or disallowed, either by agreement or otherwise, the amount available for Dynegy entities to set off against sums that might be due Enron entities could be reduced materially.
Severance Arbitrations. Dynegy Inc.’s former CEO, Chuck Watson, former President, Steve Bergstrom, and former CFO, Rob Doty, have each filed for arbitration pursuant to the terms of their employment/severance agreements. In each case, the parties disagree as to the amounts that may be owed pursuant to their respective agreements. These former officers have made arbitration claims that seek payments of up to approximately $28.7 million, $10.4 million and $3.4 million, respectively. These agreements are subject to interpretation and Dynegy Inc. has stated its belief that the amounts owed are substantially lower than the amounts sought. However, we cannot predict with any degree of certainty the amounts that may be determined to be owed as a result of the pending arbitration proceedings. Please read Note 4-Restructuring and Impairment Charges beginning on page for discussion of the accruals we have recorded with respect to these estimated severance obligations.
Modesto Litigation. On August 3, 1998, the Modesto Irrigation District filed a lawsuit against PG&E and Destec Energy, Inc. (now known as Dynegy Power Corp.), which was previously acquired by Dynegy, in federal court for the Northern District of California, San Francisco division. The lawsuit alleges violations of federal and state antitrust laws and state law tort and breach of contract claims against Destec relating to a power sale and purchase arrangement with the plaintiff in the City of Pittsburg, California. While the plaintiff’s pleadings indicate that it cannot measure its alleged damages with specificity, it has indicated that the actual damages sought from PG&E and Destec may exceed $25 million. Plaintiff also seeks a trebling of any portion of damages related to its antitrust claims. After the District Court dismissed the plaintiff’s antitrust claims on August 20, 1999 and refused to assert pendent jurisdiction over the state law claims, the plaintiff filed an appeal with the Ninth Circuit Court of Appeals and re-filed its state claims in state court. Plaintiff then agreed to execute a tolling agreement on the state law claims and to dismiss the state court case until the federal appeal was decided. Plaintiff subsequently filed in the state court a request for dismissal, which the court granted on October 25, 2000.
Although PG&E filed a Chapter 11 bankruptcy proceeding on April 6, 2001, the automatic stay applicable in the proceeding was lifted to permit the Ninth Circuit to decide the pending appeal. On December 6, 2002, the Ninth Circuit reversed the District Court’s order dismissing the plaintiff’s antitrust claims. Plaintiff has not taken any action with respect to this action since December 6, 2002. We believe that we have meritorious defenses to these claims and we intend to vigorously defend against them. However, if the plaintiff were to successfully prosecute its claims, we could be required to fund a judgment in excess of $25 million.
Farnsworth Litigation. On August 2, 2002, Bradley Farnsworth filed a lawsuit against Dynegy Inc. in Texas state district court claiming breach of contract and that he was demoted and ultimately fired from the position of Controller for refusing to participate in illegal activities. Specifically, Mr. Farnsworth alleges, in the words of his complaint, that certain of our former executive officers requested that he “shave or reduce for
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accounting purposes” the forward price curves associated with the natural gas business in the United Kingdom for the period of October 1, 2000 through March 31, 2001, in order to indicate a reduction in our mark-to-market losses. Mr. Farnsworth, who seeks unspecified actual and exemplary damages and other compensation, also alleges that he is entitled to a termination payment under his employment agreement equal to 2.99 times the greater of his average base salary and incentive compensation for the highest three calendar years preceding termination or his base salary and target bonus amount for the year of termination (currently estimated at a range of approximately $700,000 to $1,200,000). The parties have commenced discovery in this lawsuit. Dynegy Inc. has stated its belief that it has meritorious defenses against these claims and intends to vigorously defend against them. We do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition or results of operations.
Apache Litigation. In May 2002, Apache Corporation filed suit in Harris County, Texas district court against Versado Gas Processors, LLC as purchaser and processor of Apache’s gas, and against Dynegy Midstream Services, Limited Partnership as operator of the Versado assets in New Mexico. The suit, which followed an Apache audit of Versado’s books and records relating to the parties’ commercial transactions, originally sought approximately $3.9 million in damages. Under an agreed court order, Versado analyzed the results of the Apache audit and voluntarily paid approximately $1.35 million to Apache in the third quarter 2002. Apache has since amended its petition to allege Versado still owes it a total of more than $9 million. These new claims include allegations that Versado engages in “sham” transactions with affiliates, which result in Versado not receiving the true fair market values when it sells the gas and liquids. They also allege, among other things, that the formula for calculating the amount Versado receives from the buyers of the gas and liquids is flawed since it is based on gas price indexes that these same affiliates are alleged to have manipulated by providing false price information to the index publisher. Versado intends to vigorously defend against these claims and believes it has meritorious defenses. Trial in the matter is currently scheduled for late third quarter 2003. We do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition or results of operations.
Triad Energy Litigation. On March 18, 2003, Triad Energy Resources Corp. and five other alleged representatives of two plaintiffs’ classes filed a putative antitrust class action against NiSource Inc. and other defendants, including Dynegy Inc., in the United States District Court for the District of Columbia. The plaintiffs purport to represent classes of purchasers, marketers, wholesalers, managers, sellers and shippers of natural gas that allegedly were damaged by an illegal gas scheme devised by three federally regulated interstate pipeline systems: Columbia Gas Transmission Corporation, Columbia Gulf Transmission Company, and The Cove Point LNG Limited Partnership-all of which now are owned by NiSource, and certain shippers on these pipelines.
The complaint alleges violations of the federal antitrust laws and common law tortious interference with contractual and business relations. It alleges that the interstate pipelines provided preferential storage and transportation services to their own unregulated marketing affiliate in violation of FERC regulations and, in return, received percentages of the profits reaped by the marketing affiliate. The complaint also alleges that certain shippers, including us, having learned of the Columbia arrangements, demanded and received similar preferential storage and transportation services that were not available to all shippers.
Although this alleged scheme was the subject of a FERC order issued on October 25, 2000, which order required the Columbia companies to pay $27.5 million to certain customers of Columbia Gas and Columbia Gulf, plaintiffs claim that the FERC order did not remedy the competitive injury to plaintiffs caused by the scheme. The complaint seeks aggregate damages of approximately $1.716 billion (divided approximately $1.034 billion and $682 million between two plaintiffs’ classes). Under the federal antitrust laws, damages are subject to trebling. We are analyzing these claims, which only recently were made, and intend to vigorously defend against
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them. It is not possible to predict with certainty whether we will incur any liability or to estimate the damages, if any, that we might incur in connection with this lawsuit.
Alleged Marketing Contract Defaults. We have posted collateral to support a substantial portion of our obligations in our customer risk management business, including our obligations under some of our power tolling arrangements. While we have been working with various counterparties to provide mutually acceptable collateral or other adequate assurance under these contracts, we have not reached agreement with Sithe Independence and Sterlington/Quachita Power LLC regarding a mutually acceptable amount of collateral in support of our obligations under our power tolling arrangements with either of these two parties. Although we are current on all contract payments to these counterparties, we have received a notice of default from each such party with regard to collateral and are continuing to negotiate the issue. Our annual net payments under these two arrangements approximate $67 million and $57 million, respectively, and the contracts extend through 2014 and 2012, respectively. If these two parties were to successfully pursue claims that we defaulted on these contracts, they could declare a termination of their respective contracts, which provide for termination payments based on the agreed mark-to-market value of the contracts. Because of the effects of changes in commodity prices on the mark-to-market value of these contracts, as well as the likelihood that we would differ with our counterparties as to the estimated value of these contracts, we cannot predict with any degree of certainty the amounts of termination payments that could be required under these two contracts. Disputes relating to these two contracts, if resolved against us, could materially adversely affect our financial condition and results of operations.
In addition, we are involved in litigation with some of our former counterparties relating to contract terminations with respect to which we were unable to agree on mutually acceptable collateral or other adequate assurance. We intend to vigorously defend against these claims and do not expect that any liability we might incur in connection with these contract terminations will materially adversely affect our financial condition or results of operations.
U.S. Attorney Investigations. The U.S. Attorney’s office in Houston has commenced an investigation of our actions relating to Project Alpha, roundtrip trades with CMS Energy and our gas trade reporting practices. We have produced documents and witnesses for interviews in connection with this investigation. Six of our natural gas traders were dismissed in October 2002 for violating our Code of Business Conduct after an ongoing internal investigation conducted by Dynegy Inc.’s Audit and Compliance Committee in collaboration with independent counsel discovered that inaccurate information regarding natural gas trades had been reported to various energy industry publications. On January 27, 2003, one of our former natural gas traders was indicted in Houston on three counts of knowingly causing the transmission of false trade reports used to calculate the index price of natural gas and four counts of wire fraud. We are cooperating fully with the U.S. Attorney’s office in its investigation of these matters and cannot predict the ultimate outcome of this investigation.
Additionally, the United States Attorney’s office in the Northern District of California has issued a subpoena requesting information related to our activities in the California energy markets. We have been, and intend to continue, cooperating fully with the U.S. Attorney’s office in its investigation of these matters, including production of substantial documents responsive to the subpoena and other requests for information. We cannot predict the ultimate outcome of this investigation.
SEC Settlement. On September 24, 2002, Dynegy Inc. announced a settlement with the SEC of allegations made in connection with the previously disclosed investigation relating to Project Alpha and round-trip electricity trades with CMS Energy. In the settlement, the SEC found that Dynegy Inc. engaged in securities fraud in connection with its disclosures and accounting for Project Alpha, and negligently included materially misleading information about the round-trip energy trades with CMS Energy in two press releases it issued in early 2002. In settlement of the SEC’s enforcement action, Dynegy Inc., without admitting or denying the SEC’s
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findings, agreed to the entry of a cease-and-desist order and to pay a $3 million penalty in a related civil suit filed in the United States District Court in Houston, Texas. We are continuing to cooperate with the SEC’s ongoing investigation of other parties related to Project Alpha.
Nicor Energy Investigations. We own a 50% interest in Nicor Energy L.L.C., a joint venture with Nicor Inc. that markets retail gas and electricity in the Midwest. During the first quarter of 2003, substantially all of the operations of Nicor Energy have been sold and we expect to liquidate the company in the second quarter of 2003. We have historically provided gas and electricity to Nicor Energy for resale to its retail customers; however, we ceased to provide gas to Nicor Energy effective March 31, 2003 in connection with our exit from third-party marketing and trading and will cease to provide electricity to Nicor Energy in connection with its assignment of our wholesale electricity contracts to the purchasers of its retail electricity business. On March 10, 2003, Nicor Inc. publicly announced that it expects the SEC to bring civil charges against Nicor Energy based on alleged violations of standard financial reporting relating to unbilled revenues and unrecorded liabilities, including fraud and maintaining false books and records. The U.S. Attorney for the Northern District of Illinois has also notified Nicor Energy that it is conducting an inquiry on these same matters, and that a grand jury is also reviewing these matters. We intend to cooperate with these investigations and cannot predict their ultimate outcomes.
Nicor Inc. previously revealed irregularities in accounting at Nicor Energy. We have reflected a $5.6 million pre-tax charge in the fourth quarter 2001 relating to our investment in Nicor Energy as a result of these matters. We intend to divest our ownership interest in Nicor Energy consistent with our previously announced exit from third-party marketing and trading.
CFTC Investigation. The CFTC commenced an investigation in June 2002 relating to our past trading activities. The investigation covers Dynegydirect and round-trip trading and was expanded to cover our practices with respect to furnishing information regarding natural gas trades to various energy industry publications that compile and report index prices. During an internal review of our trading activities that was conducted in connection with the CFTC investigation, we discovered that certain employees in our trading business had furnished inaccurate information to various industry publications. We are one of many energy industry participants who routinely provide trade data to the publications; consequently, we cannot determine whether the inaccurate data had any impact on the published indices. In response to these findings, we now require that all price information provided to industry publications be verified by the office of our Chief Risk Officer. In addition, in October 2002, we dismissed six employees and disciplined seven others in our natural gas trading business as a result of an investigation conducted by our Audit and Compliance Committee and in collaboration with independent counsel. Settlement with the CFTC was reached on December 18, 2002 regarding the gas price index issues, pursuant to which we agreed to pay a $5 million fine and neither admitted nor denied the CFTC’s allegations of false reporting, attempted gas price manipulation and inadequate recordkeeping. The CFTC settlement also applied to West Coast Power, our 50-50 joint venture with NRG Energy. We have separately agreed to indemnify NRG Energy with respect to any liability that it might incur as a result of these issues.
Department of Labor Investigation. In August 2002, the U.S. Department of Labor commenced an official investigation pursuant to Section 504 of ERISA with respect to the benefit plans maintained by Dynegy Inc. and its ERISA affiliates. We have cooperated with the Department of Labor throughout this investigation, which remains ongoing. As of this date, the investigation has focused on a review of plan documentation, plan reporting and disclosure, plan recordkeeping, plan investments and investment options, plan fiduciaries and third-party service providers, plan contributions and other operational aspects of the plans. We have not yet received the Department of Labor’s definitive findings resulting from its investigation.
Purchase Obligations. 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
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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, ships and power generation assets. The following describes the more significant commitments outstanding at December 31, 2002.
We have routinely entered into supply and market contracts for the purchase and sale of electricity, some of which contain fixed capacity payments. Such obligations are generally payable on a ratable basis, the terms of which extend through May 2030. In return for such fixed capacity payments, we receive the right to generate electricity at agreed prices, which we then may re-market. These types of arrangements are referred to as tolling arrangements. These fixed capacity payments totaled approximately $3.8 billion at December 31, 2002.
We have other firm capacity payments related to storage and transportation of natural gas. Such arrangements are routinely used in the physical movement and storage of energy consistent with our business strategy. The total of such obligations was $595 million as of December 31, 2002, with $309 million of the $595 million due after 2007.
We have $49 million of unconditional purchase obligations related to the purchase of power, gas and coal. Pursuant to our capital asset expansion program we entered into purchase orders to acquire at least 14 gas-fired turbines, representing a capital commitment of approximately $483 million. Commitments under these purchase orders are generally payable consistent with the delivery schedule. Approximately 95% are scheduled to be delivered by the end of 2006. The purchase orders include milestone requirements by the manufacturer and provide us with the ability to cancel each discrete purchase order commitment in exchange for a fee, which escalates over time. At December 31, 2002, we could have paid approximately $48 million to cancel all 14 purchase orders.
Advance Agreement. In 1997, we received cash from a gas purchaser as an advance payment for future natural gas deliveries over a ten-year period (“Advance Agreement”). As a condition of the Advance Agreement, we entered into a natural gas swap with a third party under which we became a fixed-price payer on identical volumes to those to be delivered under the Advance Agreement at prices based on current market rates. The cash receipt is included as deferred revenue in other long-term liabilities on the consolidated balance sheets and is ratably reduced as gas is delivered to the purchaser under the terms of the Advance Agreement. The balance at December 31, 2002 approximated $57 million. The Advance Agreement contains specified non-performance penalties that impact both parties and as a condition precedent, we purchased a surety bond in support of our obligations under the Advance Agreement.
Other Minimum Commitments. We entered into a lease arrangement with IP associated with the Tilton natural gas-fired generating facility, which is accounted for as an operating lease. Under the terms of this arrangement, we have provided a residual value guarantee of approximately $70 million associated with the leased asset. Pursuant to this guarantee, IP has the option to acquire, at the end of the lease term, the leased assets for a purchase price determined at lease inception and estimated to represent fair market value at the end of the lease term. If IP does not choose to purchase the leased assets, we must perform under the terms of the residual value guarantee. We guaranteed the leased asset would maintain a value equal to at least 85% of its originally estimated fair value. If the value of the asset is less than 85% of the fair market value at lease termination, we are obligated to pay the owner the difference. Minimum commitments in connection with office space, equipment, plant sites and other leased assets, including the DNE sale-leaseback transaction discussed in Note 3-Dispositions, Discontinued Operations and Acquisitions beginning on page, at December 31, 2002, were as follows: 2003-$81 million; 2004-$150 million, 2005-$77 million; 2006-$77 million; 2007-$124 million and beyond-$1.2 billion.
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Rental payments made under the terms of these arrangements totaled $90 million in 2002, $97 million in 2001 and $75 million in 2000.
We are party to two lease agreements relating to VLGCs previously utilized in our global liquids business. The aggregate base commitments of the lease agreements are $13 million each year for the years 2003 through 2007, and $83 million through lease expiration. 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 leases to a wholly owned subsidiary of Transammonia Inc. The terms of the sub-charter are identical to the base commitments of the original lease agreements.
Guarantees. As discussed in Note 2, Statement No. 45 requires disclosure of information relating to guarantees issued. These guarantees include letters of credit, indemnities and other forms of guarantees provided by the Company to third parties.
Guarantees included letters of credits of $897 million and surety bonds totaling $112 million. At December 31, 2002, $20 million of the $112 million in surety bonds were supported by letters of credit. Approximately $31 million of the contingent financial commitments related to the surety bonds expire in 2003; however, these bonds are generally renewed on a rolling twelve-month basis.
We have indemnified various parties against specific liabilities that third parties might incur in connection with acquisitions, divestitures and leasing arrangements that we enter into. These indemnities are contingent upon the other party incurring liabilities that are not recoverable from other third parties and reach a certain threshold. Indemnities provided under such contracts are customary in these types of arrangements, particularly for the Rough and Hornsea sales contract, where it is common practice in Europe to cap such indemnities at the purchase price paid. The indemnities relate to breach of warranties and terms of contracts, tax indemnifications, performance guarantees, compliance with laws and regulations, environmental and employee-related matters. At December 31, 2002, we do not expect any of the indemnities provided to third parties to have a material impact on our financial statements. However, if a liability is brought against us under such indemnity in the future, it may have a material adverse effect to the consolidated financial position.
In connection with the sale of Northern Natural, the Hornsea gas storage facility, and certain DMS assets, we have provided certain indemnities to third parties acquiring the assets. Environmental liability indemnities provided in connection with the sale of certain DMS assets have a maximum loss threshold of $28 million. Indemnities provided in connection with the sale of other assets relate to environmental, tax, employee and other representations provided by the company. Maximum recourse under such indemnities under the Northern Natural, Rough and Hornsea storage facilities total $209 million, £316 million (approximately $510 million at December 31, 2002) and £130 million (approximately $210 million at December 31, 2002), respectively. As of December 31, 2002, we are not aware of any circumstance that would lead to future indemnity claims in connection with these transactions.
We have also provided a performance and replacement cost guarantee under a power purchase agreement related to our Rockingham power generation facility. The $21 million guarantee secures our obligation to deliver capacity from energy to a third party under the terms of the agreement.
NOTE 15-REGULATORY ISSUES
We are subject to regulation by various federal, state, local and foreign 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
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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. In addition, the United States Congress has before it a number of bills that could impact regulations or impose new regulations applicable to us and our subsidiaries. We cannot predict the outcome of these bills or other regulatory developments or the effects that they might have on our business.
NOTE 16-CAPITAL STOCK
All of our outstanding equity securities are held by our parent, Dynegy Inc. There is no established trading market for such securities, and they are not traded on any exchange.
Stock Options. Our parent grants stock options, from time to time, to certain of our employees. Each option granted is valued at an option price, which ranges from $0.88 per share to $57.95 per share at date of grant. The difference, if any, between the option price and the intrinsic value of each option on the date of grant is recorded as compensation expense over the respective vesting period.
Dynegy Inc. has six stock option plans in which we participate; all of which contain authorized shares of its Class A common stock. A brief description of each plan is provided below.
NGC Plan. Created early in Dynegy Inc.’s history and revised prior to Dynegy Inc. becoming a publicly traded company in 1996, this plan contains 13,651,802 authorized shares, has a ten-year term, and expires in May 2006. All option grants are vested.
Employee Equity Plan. This plan expired in May 2002 and is the only plan in which we granted options below the fair market value of Class A common stock on the date of grant. This plan contains 20,358,802 authorized shares, and grants from this plan vest in equal annual installments over a five-year period.
UK Plan. This plan contains 276,000 authorized shares and has been terminated. All grants are vested.
Dynegy 1999 Long-Term Incentive Plan (LTIP). This annual compensation plan contains 6,900,000 authorized shares, has a ten-year term and expires in 2009. All grants are vested.
Dynegy 2000 LTIP. This annual compensation plan, created for all employees upon the merger date of Illinova and Dynegy Inc., contains 10,000,000 authorized shares, has a ten-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. Created at the discretion of Dynegy Inc.’s Board of Directors, this plan contains 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 contains 10,000,000 authorized shares, has a ten-year term and expires in May 2012. Grants from this plan vest in equal annual installments over a three-year period.
All of our option plans cease vesting for employees who are terminated for cause. For voluntary and involuntary termination, disability, or death, all of our option plans cease vesting, with the exception of the Employee Equity Plan, which contains partial vesting provisions for the events noted above.
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Compensation expense related to options granted totaled $9 million and $15.4 million for the years ended December 31, 2001 and 2000, respectively. Compensation expense in 2001 includes $1 million related to charges incurred due to the extension of the exercise period of various stock options and the acceleration of vesting for various other stock options. Total options outstanding and exercisable for 2002, 2001 and 2000 were as follows (options in thousands):
Options outstanding as of December 31, 2002 (options in thousands) are summarized below:
Pursuant to terms of the Illinova acquisition, certain vesting requirements on outstanding options were accelerated and the option shares and strike prices were subject to the exchange ratios described in the acquisition documents. Additionally, we instituted new option plans on the effective date of the acquisition.
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NOTE 17-EMPLOYEE COMPENSATION, SAVINGS AND PENSION PLANS
Short-Term Bonus Incentive Plan. Our parent maintains a discretionary incentive plan to provide employees with what we believe to be competitive and meaningful rewards for reaching corporate and individual objectives. Specific awards are at the discretion of the Compensation Committee of the Dynegy Inc. Board of Directors (“Compensation Committee”).
401(k) Savings Plan. Our parent established the Dynegy Inc. 401(k) Savings Plan (“Dynegy Plan”), which meets the requirements of Section 401(k) of the Internal Revenue Code, and is a defined contribution plan subject to the provisions of the Employee Retirement Income Security Act of 1974 (“ERISA”). The Plan and related trust fund are established and maintained for the exclusive benefit of participating employees in the United States and certain expatriates. Similar plans are available to other employees resident in foreign countries and are subject to the laws of each country. All employees of certain entities are eligible to participate in the Plan. Employee pre-tax contributions to the Plan are matched 100%, up to a maximum of five percent of base pay, subject to IRS limitations. Vesting in our contributions is based on years of service. We may also make discretionary contributions to employee accounts, subject to our performance. Matching contributions to the Plan and discretionary contributions are made in Dynegy Inc. common stock. During the years ended December 31, 2002, 2001 and 2000, we issued approximately 2.6 million, 0.3 million and 0.5 million shares, respectively, of Dynegy Inc. common stock to fund the plan. We discontinued the additional 5% profit sharing contribution to active employee accounts in 2001. However, active employees who normally would have received the profit sharing contribution under the Dynegy Plan began participating in the pension plan in 2001 (see below).
Certain eligible employees participate in the Dynegy Northeast Generation, Inc. Savings Incentive Plan (“Northeast Plan”), which meets the requirements of Section 401(k) of the Internal Revenue Code and is a defined contribution plan subject to the provisions of ERISA. Under the Northeast Plan, for representative (union) employees, we match 24% of employee contributions up to 6 percent of base salary. For non-representative (non-union) employees, we match 50% of employee contributions up to 8 percent of base salary. Our guaranteed match is subject to a maximum of six or eight percent of base pay, subject to IRS limitations. Employees are immediately 100% vested in our contributions. Matching contributions to the Northeast Plan are made in cash.
During the years ended December 31, 2002, 2001 and 2000, we recognized aggregate costs related to these employee compensation plans of $10 million, $17 million and $15 million, respectively.
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Pension and Other Post-Retirement Benefits. We have various defined benefit pension plans and post-retirement benefit plans. All domestic employees participate in the pension plans, but only some of our domestic employees participate in the other post-retirement benefit plans. We added a cash balance feature effective for 2001 and thereafter with respect to employees who would have otherwise received a profit sharing contribution under the Dynegy Plan for 2001 and thereafter (the contribution credit under such cash balance feature shall generally be six percent of base pay). The following tables contain information about these plans on a combined basis ($ in millions):
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The changes in the projected benefit obligations and in plan assets attributable to business combination in 2001 are the result of the DNE acquisition.
On December 31, 2002, our annual measurement date, the accumulated benefit obligation related to our pension plans exceeded the fair value of the pension plan assets. This difference is attributed to (1) an increase in the accumulated benefit obligation that resulted from a decrease in the discount rate and the expected long-term rate of return and (2) a decline in the fair value of the plan assets due to a sharp decrease in the equity markets through December 31, 2002. As a result, in accordance with Statement of Financial Accounting Standards No. 87, “Employers’ Accounting for Pensions,” we recognized a charge to accumulated other comprehensive loss of $3 million (net of taxes of $2 million), which decreased stockholder’s equity.
The components of net periodic benefit cost were (in millions):
Impact of a one percent increase/decrease in medical trend (in millions):
NOTE 18-SEGMENT INFORMATION
Our operations for the periods presented have been reported in three segments primarily based on the type of services provided and markets served: WEN, DMS and T&D. WEN has historically been engaged in a broad array of businesses, including physical supply of, and risk-management activities around, wholesale natural gas, power, coal, and other similar products. This segment’s focus has been to optimize our, as well as our customers’, global portfolio of energy assets and contracts, as well as direct commercial and industrial sales and retail marketing alliances. DMS consists of our North American midstream gas processing and NGL marketing businesses and worldwide NGLs marketing and transportation operations. Our T&D segment includes the operations of Northern Natural.
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As further described in Note 3-Dispositions, Discontinued Operations and Acquisitions beginning on page, in the fourth quarter 2002, the DMS segment sold its global liquids business, the WEN segment sold its UK storage business; and in August 2002, the T&D segment sold its Northern Natural operations. The results of all of these sold businesses are presented as discontinued operations in the consolidated statements of operations.
Pursuant to our announced restructuring plans, beginning in 2003, we will report our operations in the following three business segments:
•
Power generation
•
Natural gas liquids
•
Customer risk management
Other reported results will include corporate overhead.
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Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the years ended December 31, 2002, 2001 and 2000 is presented in the following tables:
DYNEGY’S SEGMENT DATA FOR THE YEAR ENDED DECEMBER 31, 2002
( in millions)
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DYNEGY’S SEGMENT DATA FOR THE YEAR ENDED DECEMBER 31, 2001
(in millions)
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DYNEGY’S SEGMENT DATA FOR THE YEAR ENDED DECEMBER 31, 2000
(in millions)
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NOTE 19-QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Our restatements, which are described in the Explanatory Note to Amendment No. 1 to our 2001 Form 10-K/A, affect the results previously reported on a quarterly basis for 2002. Set forth in this Note 19-Quarterly Financial Information (Unaudited) is a summary description of the effect of the restatements on our quarterly condensed consolidated financial statements previously filed with our Forms 10-Q for the quarterly periods ended September 30, 2002, June 30, 2002 and March 31, 2002. We expect to file amendments to each of the aforementioned Forms 10-Q to reflect the restatements. The restatements relate to the following items:
•
the Project Alpha structured natural gas transaction,
•
a balance sheet reconciliation project relating principally to our natural gas marketing business,
•
corrections to our previous hedge accounting for certain contracts resulting in our accounting for these contracts pursuant to the mark-to-market method under Statement No. 133; in addition, we determined that we had incorrectly accounted for certain derivative transactions prior to the adoption of Statement No. 133,
•
the restatement of our forward power curve methodology to reflect forward power and market prices more closely,
•
the recognition of additional assets, accrued liabilities and debt associated with certain lease arrangements, as well as depreciation and amortization expense for the related assets,
•
the recognition of an other-than-temporary decline in value of a technology investment in the third quarter of 2001 rather than the second quarter of 2002,
•
corrections to our previous accounting for income taxes, and
•
other adjustments that arose during the re-audit of our 1999-2001 financial statements.
Specifically, the restatements are as follows:
Project Alpha. We entered into the Project Alpha structured natural gas transaction in April 2001. As described in a Current Report on Form 8-K dated April 25, 2002 (the “Alpha Form 8-K”), we restated the cash flow associated with the related gas supply contract as a financing activity in our Consolidated Statement of Cash Flows for 2001. The effect of this restatement was to reclassify approximately $290 million of previously disclosed 2001 operating cash flow to financing cash flow. Following the disclosure in the Alpha Form 8-K and in connection with a further review of Project Alpha, Arthur Andersen, LLP (“Arthur Andersen”) informed us that it could no longer support its tax opinion relating to the transaction. Arthur Andersen’s change in position was based in part on its conclusion that the reclassification of cash flow from operations to cash flow from financing lessened the factual basis for the opinion. Our financial statement recognition of the tax benefit in 2001 was based principally on our assessment of the relevant issues, as corroborated by Arthur Andersen’s tax opinion. After the withdrawal of Arthur Andersen’s tax opinion, we concluded that sufficient support to include the income tax benefit for financial statement presentation purposes no longer existed, the effect of which was a reversal of approximately $79 million of tax benefit we previously recognized during the 2001 period. Arthur Andersen further advised us that its audit opinion relating to 2001 should no longer be relied upon as a result of the pending restatements relating to Project Alpha and such audit opinion has been withdrawn. We subsequently concluded that our 2001 restated consolidated financial statements would include the consolidation of ABG Gas Supply, LLC (“ABG”), one of the entities formed in connection with the transaction. The consolidation of ABG is included herein based on compilations of financial information received from an agent of ABG’s equity holders.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The table below reflects the quarterly impact of the Project Alpha restatements on net income as originally reported in the applicable 2002 quarterly reports. We reflected these restatements in our third quarter 2002 Form 10-Q filed on November 19, 2002; consequently, as reflected in the table below, these restatements do not impact the three- and nine-month results we previously reported in our third quarter 2002 Form 10-Q.
Balance Sheet Reconciliation Project. We recognized an after-tax charge of approximately $80 million ($124 million pre-tax) in the second quarter 2002 related to a balance sheet reconciliation project undertaken by us at the beginning of 2002. The charge related principally to our natural gas marketing business and was associated with the process of reconciling accrued to actual results. Accrual accounting for natural gas marketing involves the estimation of gas volumes bought, sold, transported and stored, as well as the subsequent reconciliation from estimated to actual volumes. We have restated our financial statements to allocate this $80 million charge from the second quarter 2002 back to the periods in which the transactions giving rise to the charge originally occurred. The table below reflects the impact on net income of this restatement. We partially reflected this restatement in our third quarter 2002 Form 10-Q filed on November 19, 2002; consequently, the amounts included below for the three- and nine-month periods ended September 30, 2002 are incremental to the related amounts we originally reported in our third quarter 2002 Form 10-Q.
Corrected Hedge Accounting. We adopted Statement No. 133 effective January 1, 2001 and reflected certain contracts as cash flow hedges upon such adoption. Management has subsequently determined that following the initial adoption of Statement No. 133, the documentation of compliance requirements under the standard, particularly as it relates to documentation and the periodic assessment of hedge effectiveness, was inadequate to support the accounting method previously applied. In addition, we determined that we had incorrectly accounted for certain derivative transactions prior to the adoption of Statement No. 133. The resulting restatement reflects the accounting for these contracts on a mark-to-market basis rather than on the hedge accounting basis previously employed. The correction in the accounting for these contracts had no impact on previously reported cash flows from operations in any period.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The table below reflects the impact of this restatement on net income as originally reported in the applicable 2002 quarterly reports. We reflected portions of this restatement in our third quarter 2002 Form 10-Q filed on November 19, 2002. The restatement items identified subsequent to November 19, 2002 are included in the following table:
Restated Forward Power Curve Methodology. We value substantially all of our natural gas marketing, power marketing and portions of our natural gas liquids marketing operations under a mark-to-market accounting methodology. The estimated fair value of the marketing and trading portfolio is computed by multiplying all existing positions in the portfolio by estimated prices, reduced by a LIBOR-based time value of money adjustment and deduction of reserves for credit, price and market liquidity risks. We use a combination of market quotes, derivatives of market quotes and proprietary models to periodically value this portfolio as required by GAAP. Market quotes are used for near-term transactions, where such quotes are generally available; derivatives of market quotes are used for mid-term transactions, where broker quotes are only marginally available; and proprietary models are used for long-term transactions, where broker quotes or other objective pricing indicators typically are not available. Beginning in the third quarter 2001, we began to enter into longer-term power transactions in the United States with respect to which no broker quotes or other market data was available; consequently, we applied a proprietary model to estimate forward prices and, in turn, the fair market value of these longer-term power transactions.
During January 2003, in connection with the re-audit of our 1999-2001 financial statements and an assessment of various accounting policies, we reconsidered the model-based methodology we used to value the portions of our power marketing and trading portfolio for which broker quotes were not available. Under our prior methodology, forward curves used to calculate the value of our long-term U.S. power contracts were derived from a proprietary model based on a required rate of return on investments in new generation facilities. The primary disadvantage of this type of methodology, which was confirmed by our former independent auditors, is that, in certain circumstances, it may not reflect true market prices in future years. After reconsidering the appropriateness of this methodology and in connection with the re-audit, in late January 2003, we determined that, beginning with the third quarter 2001, a different forward power curve methodology would more appropriately reflect the value of our long-term power contracts.
Upon making this determination, we corrected the forward power curve methodology we used to estimate the fair market value of our U.S. power marketing and trading portfolio. This corrected methodology incorporates forward energy prices derived from broker quotes and values from executed transactions to estimate forward price curves for periods where broker quotes and transaction data cannot be obtained. Further, we determined that in order to adequately reflect our results, it was appropriate to restate our prior period financial statements, beginning with the third quarter 2001, to reflect the corrected methodology.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The table below reflects the impact of this restatement on net income as originally reported in the applicable 2002 quarterly reports.
Restated Lease Accounting. We previously accounted for seven generation lease arrangements as operating leases. Our previous accounting treatment of these lease arrangements, which was confirmed by our former prior independent auditors prior to the withdrawal of their audit opinion for unrelated matters, reflected our belief that these arrangements satisfied the applicable GAAP requirements so as to justify their treatment as operating leases. However, these requirements are very technical and subject to a high degree of interpretation. During the course of the re-audit of our financial statements for 1999-2001, we analyzed our accounting for these arrangements and considered a variety of factors, including interpretations of the applicable GAAP requirements. Upon completion of this analysis and discussions with PricewaterhouseCoopers LLP, in January 2003, we determined it necessary to correct our accounting for these lease arrangements to recognize on our balance sheet the related assets as of the inception of five of these arrangements. Although we previously amended the agreements relating to six generation lease arrangements so as to require them to be treated as capital leases in the second quarter 2002, our restatement of the accounting we originally applied to these arrangement results in the recognition of the related assets as of an earlier date. Consequently, our previously reported net income has been reduced, reflecting the recognition of depreciation and amortization expenses associated with the related assets. In addition, balance sheet amounts have been adjusted for this change as follows:
Please read Note 10-Debt beginning on page for further discussion.
The table below reflects the impact of this restatement on net income as originally reported in the applicable 2002 quarterly reports.
Valuation of Technology Investment. We acquired the common stock of a technology investment in the second quarter 2000. In the second quarter 2002, after several quarters of declines in the market price of the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
investment, we determined that the decline in value was other-than-temporary. As such, we recognized a $12 million after-tax charge during the second quarter 2002. Upon further review, we determined that we incorrectly delayed recognition of the charge associated with this investment, as the decline in value through September 30, 2001 met the “other-than-temporary” threshold. Therefore, we have restated the financial statements to record the impairment in the third quarter 2001.
The table below reflects the impact of this restatement on net income as originally reported in the applicable 2002 quarterly reports.
Correction for Income Taxes. During the course of the re-audit of our 1999-2001 financial statements, we reviewed our previous accounting for income taxes and determined that we made errors in accounting for certain tax matters. These errors related to book-tax basis differences that were reflected as permanent differences as opposed to temporary differences, the failure to record differences between the amounts recognized as income tax provision and the amounts actually reflected in the applicable income tax returns, adjustments related to book and tax-basis balance sheet reconciliations and changes in estimates of tax contingencies. We have restated our financial statements to correct these errors, resulting in additional deferred tax expense as further described below.
The table below reflects the impact of these restatements on net income as originally reported in the applicable 2002 quarterly reports.
Other Adjustments Arising During Re-Audit. As described in the Introductory Note, PricewaterhouseCoopers LLP has re-audited our 1999-2001 financial statements. The re-audit was completed in April 2003. We have restated our 1999-2001 financial statements, as well as our 2002 quarterly financial data, to correct various errors in our historical financial statements that were identified during the course of the re-audit. The corrections principally relate to the timing on which various transactions were recorded in the ordinary course of business.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The table below reflects the impact of these restatements on net income as originally reported in the applicable 2002 quarterly reports.
A synopsis of the aggregate financial impact of these restatements on the amounts originally reported in the 2002 Form 10-Qs for the quarterly periods ended September 30, 2002, June 30, 2002 and March 31, 2002, filed on November 19, 2002, August 14, 2002 and May 20, 2002, respectively, is as follows (in millions):
RESTATED SELECTED BALANCE SHEET DATA BY QUARTER
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
RESTATED RESULTS OF OPERATIONS BY QUARTER
(1)
Information included within our Form 10-Q filed on November 19, 2002, which included results for the three- and nine-month periods ended September 30, 2002, presented revenues net in accordance with EITF 02-03. In addition, this Form 10-Q included the results of operations of Northern Natural and UK storage in discontinued operations.
(2)
As further described in the detail on pages through, certain adjustments were already reflected in the Form 10-Q filed on November 19, 2002, which included results for the three- and nine-month periods ended September 30, 2002.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(1)
Information included within our Form 10-Q filed on November 19, 2002, which included results for the three- and nine-month periods ended September 30, 2001, presented revenues net in accordance with EITF 02-03. In addition, the Form 10-Q includes the results of operations of Northern Natural and UK storage in discontinued operations.
(2)
As further described in the detail on pages through, certain adjustments were already reflected in the Form 10-Q filed November 19, 2002, which included results for the three- and nine-month periods ended September 30, 2001.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
RESTATED SELECTED CASH FLOW DATA BY QUARTER
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The following is a summary of our unaudited quarterly financial information for the years ended December 31, 2002 and 2001.
NOTE 20-LIQUIDITY
We faced significant challenges relating to our liquidity position in 2002. These challenges were caused by several factors affecting the merchant energy industry, and particularly our company, including the following:
•
The application of more stringent credit standards to Dynegy and other energy merchants;
•
Weak commodity prices, particularly for power;
•
A reduction in liquidity and the amount of open trade credit available to counterparties in the marketing and trading business;
•
The various lawsuits and governmental investigations involving our company, including matters relating to Project Alpha, our past trading practices and our activities in the California power market;
•
Downgrades in our credit ratings to well below investment grade, resulting in substantial requirements to provide counterparties with collateral support in order to transact new business or avoid the termination of existing transactions; and
•
The restatement of our 1999-2001 financial results, the related three-year re-audit and the unavailability of 2001 audited financial statements, all of which limited our ability to access the capital markets.
We also were negatively impacted by our inability to generate the expected return on the significant capital we had previously invested in our new merchant generation facilities, because of a weak pricing environment.
In relation to these events, we posted significantly higher amounts of collateral in the forms of cash and letters of credit than we had in the past. For example, at September 30, 2002, we had posted approximately $1.2 billion of letters of credit and cash collateral in support of our marketing and trading and asset-based businesses. This compares to the approximately $448 million in collateral that we had posted at December 31, 2001.
Since September 30, 2002, we have made marked progress in our exit from third-party risk management aspects of the marketing and trading business. The actions taken in this regard, particularly the transfer of the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
ChevronTexaco natural gas marketing business back to ChevronTexaco and the completion of our exit from U.K. marketing and trading, resulted in the return of approximately $250 million of collateral and the elimination of these collateral requirements going forward. However, our ongoing asset businesses will continue to manage commodity price risk and optimize commercial positions associated with their respective operations through, among other things, fuel procurement optimization and the marketing of power and NGLs. We expect to continue to post collateral to support these operations, the amount and term of which will be impacted by changes in commodity prices. While the completion of our exit from third-party risk management aspects of the marketing and trading business will result in a reduction in the collateral requirements associated with that business, we expect an increase in the collateral requirements relating to fuel procurement for our asset-based businesses given our non-investment grade credit ratings and higher commodity prices.
We have also successfully completed a restructuring of our revolving credit facilities that were to expire in April and May of this year. By extending the maturity date of these obligations, which totaled approximately $1.3 billion at April 2, 2003, together with the successful execution of our other liquidity initiatives, we believe that we have provided our company with sufficient capital resources to meet our current debt obligations and provide collateral support for our ongoing asset businesses and our continued exit from third-party marketing and trading. However, our long term success and future financial condition, including our ability to refinance our substantial debt maturities in 2005 and thereafter, will depend on our ability to successfully execute the remainder of our exit from third-party marketing and trading and to produce adequate operating cash flows from our continuing asset-based businesses to meet our debt and commercial obligations, including substantial increases in interest expense.
Schedule II
DYNEGY HOLDINGS INC.
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2002, 2001, and 2000
(1)
Changes in price and credit reserves related to risk management activities are offset in the net mark-to-market income accounts reported in revenues.