Item 1. Business.
GENERAL
Duke Capital LLC (collectively with its subsidiaries, Duke Capital), a wholly owned subsidiary of Duke Energy Corporation (Duke Energy), is a leading energy company located in the Americas with an affiliated real estate operation. Duke Capital provides its services through the business segments described below. On March 1, 2004, Duke Capital changed its form of organization from a corporation to a Delaware limited liability company by effecting a conversion pursuant to section 266 of the General Corporation Law of the State of Delaware and Section 18-214 of the Delaware Limited Liability Company act. Pursuant to the conversion, all rights and liabilities of Duke Capital in its previous corporate form vested in Duke Capital as a limited liability company.
Duke Capital operates the following business units: Natural Gas Transmission, Field Services, Duke Energy North America (DENA), International Energy and Crescent Resources, LLC (Crescent). Duke Capital’s chief operating decision maker regularly reviews financial information about each of these business units in deciding how to allocate resources and evaluate performance. The entities under each business unit have similar economic characteristics, services, production processes, distribution methods and regulatory concerns. All of the Duke Capital business units are considered reportable segments under Statement of Financial Accounting Standards (SFAS) No. 131, “Disclosures about Segments of an Enterprise and Related Information.”
Natural Gas Transmission provides transportation and storage of natural gas for customers along the U.S. East Coast, the Southeast, and in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail customers in Ontario, and natural gas processing services to customers in Western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission, LLC. Duke Energy Gas Transmission, LLC’s natural gas transmission and storage operations in the U.S. are primarily subject to the Federal Energy Regulatory Commission’s (FERC’s) and the U.S. Department of Transportation’s (DOT’s) rules and regulations, while natural gas gathering, processing, transmission, distribution and storage operations in Canada are primarily subject to the rules and regulations of the National Energy Board (NEB) and the Ontario Energy Board (OEB). Texas Eastern Transmission LP (Texas Eastern) is an indirect subsidiary of Natural Gas Transmission and was also a separate Securities and Exchange Commission (SEC) reporting entity. On December 15, 2004, Texas Eastern announced that it filed a Form 15 with the SEC to suspend its reporting obligations under the Securities Exchange Act of 1934. Texas Eastern is eligible to suspend its reporting obligation under the 1934 Act because it has fewer than 300 holders of record of any class of its securities.
Field Services gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, trades and markets, and stores natural gas liquids (NGLs). It conducts operations primarily through Duke Energy Field Services, LLC (DEFS), which is approximately 30% owned by ConocoPhillips and approximately 70% owned by Duke Capital. Field Services gathers raw natural gas through gathering systems located in eight major natural gas producing regions: Permian Basin, Mid-Continent, ArklaTex, Gulf Coast, South, Central, Rocky Mountains and Western Canada. DEFS, which previously was a separate SEC reporting entity, announced January 31, 2005 that it filed a Form 15 with the SEC to suspend its reporting obligations under the Securities Exchange Act of 1934. DEFS is eligible to suspend its reporting obligations under the 1934 Act because it has fewer than 300 holders of record of any class of its securities.
In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to cause a Duke Capital subsidiary to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. Upon completion of this transaction, DEFS will be owned 50% by Duke Capital and 50% by ConocoPhillips. As a result, Duke Capital expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction. This transaction, which is subject to customary U.S. and Canadian regulatory approvals, is expected to close in the latter half of 2005. Additionally, in February 2005, DEFS sold its wholly-owned subsidiary, Texas Eastern Products Pipeline Company LLC (TEPPCO), the general partner of TEPPCO Partners, L.P., for approximately $1.1 billion and Duke Capital sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each
case to Enterprise GP Holdings L.P. (EPCO), an unrelated third party. TEPPCO Partners, L.P. is a publicly traded master limited partnership which owns one of the largest common-carrier pipelines of refined petroleum products and liquefied petroleum gases in the United States, as well as natural gas gathering systems, petrochemical and NGL pipelines, and is engaged in crude oil transportation, storage, gathering and marketing. TEPPCO is responsible for the management and operations of TEPPCO Partners, L.P.
DENA operates and manages power plants and markets electric power and natural gas related to these plants and other contractual positions. DENA conducts business throughout the U.S. and Canada through Duke Energy North America, LLC and its 100% owned affiliates Duke Energy Marketing America, LLC and Duke Energy Marketing Canada Corp. DENA also participates in Duke Energy Trading and Marketing, LLC (DETM). DETM is 40% owned by ExxonMobil Corporation and 60% owned by Duke Capital.
International Energy operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. and Canada. It conducts operations primarily through Duke Energy International, LLC (DEI) and its activities target power generation in Latin America. Additionally, International Energy owns an equity investment in National Methanol Company, located in Saudi Arabia, which is a leading regional producer of methanol and methyl tertiary butyl ether (MTBE).
Crescent develops and manages high-quality commercial, residential and multi-family real estate projects primarily in the southeastern and southwestern United States. Some of these projects are developed and managed through joint ventures. Crescent also manages “legacy” land holdings in North and South Carolina.
The remainder of Duke Capital’s operations is presented as “Other”. While it is not considered a business segment, Other primarily includes certain unallocated corporate costs, DukeNet Communications, LLC (DukeNet), Bison Insurance Company Limited (Bison), Duke Capital’s wholly owned, captive insurance subsidiary, and Duke Capital’s 50% interest in Duke/Fluor Daniel (D/FD). DukeNet develops, owns and operates a fiber optic communications network primarily in the Carolinas, serving wireless, local and long-distance communications companies, Internet service providers and other businesses and organizations. Bison’s principle activities, as a captive insurance entity, include the insurance and reinsurance of various business risks and losses, such as workers compensation, property, business interruption and general liability of subsidiaries and affiliates of Duke Capital. Bison also participates in reinsurance activities with certain third parties, on a limited basis. D/FD is a 50/50 partnership between subsidiaries of Duke Capital and Fluor Corporation. During 2003, Duke Capital and Fluor Corporation announced that they would dissolve the D/FD partnership. The D/FD partners adopted a plan for an orderly wind-down of the business which is expected to be completed by December 2005. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide. During 2003, Duke Capital decided to exit the merchant finance business conducted by Duke Capital Partners, LLC (DCP). DCP had been previously included in Other. At December 31, 2004 Duke Capital had exited the merchant finance business, and all of the results of operations for DCP have been classified as discontinued operations in the accompanying Consolidated Statements of Operations.
Terms used to describe Duke Capital’s business are defined below.
Accrual Model of Accounting (Accrual Model). An accounting term used by Duke Capital to refer to contracts for which there is generally no recognition in the Consolidated Statements of Operations for any changes in fair value until the service is provided or the associated delivery period occurs or there is hedge ineffectiveness. As discussed further in Note 1 to the Consolidated Financial Statements, this term is applied to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, as well as to non-derivative contracts used for commodity risk management purposes. As this term is not explicitly defined within U.S. Generally Accepted Accounting Principles (GAAP), Duke Capital’s application of this term could differ from that of other companies.
Allowance for Funds Used During Construction (AFUDC). A non-cash accounting convention of regulatory utilities that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in the property accounts and included in income.
British Thermal Unit (Btu). A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.
Cubic Foot (cf). The most common unit of measurement of gas volume; the amount of natural gas required to fill a volume of one cubic foot under stated conditions of temperature, pressure and water vapor.
Derivative. A financial instrument or contract in which its price is based on the value of underlying securities, equity indices, debt instruments, commodities or other benchmarks or variables. Often used to hedge risk, derivatives involve the trading of rights or obligations, but not the direct transfer of property. Gains or losses on derivatives are often settled on a net basis.
Distribution. The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
Energy Marketing. Identification and execution of physical energy related transactions, generally with customized provisions to meet the needs of the customer or supplier, throughout the supply chain.
Environmental Protection Agency (EPA). The U.S. agency that is responsible for researching and setting national standards for a variety of environmental programs, and delegates to states the responsibility for issuing permits and for monitoring and enforcing compliance.
Federal Energy Regulatory Commission (FERC). The U.S. agency that regulates the transportation of electricity and natural gas in interstate commerce and authorizes the buying and selling of energy commodities at market-based rates.
Forward Contract. A contract in which the buyer is obligated to take delivery, and the seller is obligated to deliver a specified amount of a commodity with a predetermined price formula on a specified future date, at which time payment is due in full.
Fractionation/Fractionate. The process of separating liquid hydrocarbons from natural gas into propane, butane, ethane and other related products.
Futures Contract. A contract, usually exchange traded, in which the buyer is obligated to take delivery and the seller is obligated to deliver a fixed amount of a commodity at a predetermined price on a specified future date.
Gathering System. Pipeline, processing and related facilities that access production and other sources of natural gas supplies for delivery to mainline transmission systems.
Generation. The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in megawatt-hours.
Independent System Operator (ISO). An entity that acts as the transmission provider for a regional transmission system, providing customers access to the system and clearing all bilateral contract requests for use of the electric transmission system. An ISO also shares responsibility for maintaining bulk electric system reliability.
Liquefied Natural Gas (LNG). Natural gas that has been converted to a liquid by cooling it to minus 260 degrees Fahrenheit.
Liquidity. The ease with which assets or products can be traded without dramatically altering the current market price.
Local Distribution Company (LDC). A company that obtains the major portion of its revenues from the operations of a retail distribution system for the delivery of electricity or gas for ultimate consumption.
Logistics & Optimization. The act of maximizing returns from physical positions through arbitrage, especially on contractual assets such as storage, transportation, generation and transmission.
Mark-to-Market Model of Accounting (MTM Model). An accounting term used by Duke Capital to refer to derivative contracts for which an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in the Consolidated Statements of Operations. As discussed further in Note 1 to the Consolidated Financial Statements, this term is applied to trading and undesignated non-trading derivative contracts. As this term is not explicitly defined within U.S. GAAP, Duke Capital’s application of this term could differ from that of other companies.
Natural Gas. A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.
Natural Gas Liquids (NGLs). Liquid hydrocarbons extracted during the processing of natural gas. Principal commercial NGLs include butanes, propane, natural gasoline and ethane.
No-notice Bundled Service. A pipeline delivery service which allows customers to receive or deliver gas on demand without making prior nominations to meet service needs and without paying daily balancing and scheduling penalties.
Origination. Identification and execution of physical energy related transactions, generally with customized provisions to meet the needs of the customer or supplier, throughout the supply chain.
Option. A contract that gives the buyer a right but not the obligation to purchase or sell an underlying asset at a specified price at a specified time.
Peak Load. The amount of electricity required during periods of highest demand. Peak periods fluctuate by season, generally occurring in the morning hours in winter and in late afternoon during the summer.
Portfolio. A collection of assets, liabilities, transactions, or trades.
Regional Transmission Organization (RTO). An independent entity which is established to have “functional control” over utilities’ transmission systems, in order to expedite transmission of electricity. RTO’s typically operate markets within their territories.
Reliability Must Run. Generation that an ISO determines is required to be on-line to meet applicable reliability criteria requirements.
Residue Gas. Gas remaining after the processing of natural gas.
Spark Spread. The difference between the value of electricity and the value of the gas required to generate the electricity at a specified heat rate.
Swap. A contract to exchange cash flows in the future according to a prearranged formula.
Throughput. The amount of natural gas or NGLs transported through a pipeline system.
Tolling. Arrangement whereby a buyer provides fuel to a power generator and receives generated power in return for a specified fee.
Transmission System (Natural Gas). An interconnected group of natural gas pipelines and associated facilities for transporting natural gas in bulk between points of supply and delivery points to industrial customers, LDCs, or for delivery to other natural gas transmission systems.
Volatility. An annualized measure of the fluctuation in the price of an energy contract.
Watt. A measure of power production or usage equal to one joule per second.
The following sections describe the business and operations of each of Duke Capital’s business segments. (For more information on the operating outlook of Duke Capital and its segments, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Introduction-Overview of Business Strategy and Economic Factors for Duke Capital’s Business”. For financial information on Duke Capital’s business segments, see Note 3 to the Consolidated Financial Statements, “Business Segments.”)
NATURAL GAS TRANSMISSION
Natural Gas Transmission provides transportation and storage of natural gas for customers along the U.S. East Coast, the Southeast, and in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail customers in Ontario, and gas processing services to customers in western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission LLC.
For 2004, Natural Gas Transmission’s proportional throughput for its pipelines totaled 3,332 trillion British thermal units (TBtu), compared to 3,362 TBtu in 2003. This includes throughput on Natural Gas Transmission’s wholly owned U.S. and Canadian pipelines and its proportional share of throughput on pipelines that are not wholly owned. A majority of Natural Gas Transmission’s contracted transportation volumes are under long-term firm service agreements with LDC customers in the pipelines’ market areas. Firm transportation services are also provided to gas marketers, producers, other pipelines, electric power generators and a variety of end-users. In addition, the pipelines provide both firm and interruptible transportation to various customers on a short-term or seasonal basis. Demand on Natural Gas Transmission’s pipeline systems is seasonal, with the highest throughput occurring during colder periods in the first and fourth calendar quarters. Natural Gas Transmission’s pipeline systems consist of more than 17,500 miles of transmission pipelines. The pipeline systems receive natural gas from major North American producing regions for delivery to markets primarily in the Mid-Atlantic, New England and Southeastern states, Ontario, Alberta, and British Columbia. (For detailed descriptions of Natural Gas Transmission’s pipeline systems, see “Properties-Natural Gas Transmission”.)
Natural Gas Transmission, through Market Hub Partners (MHP), wholly owns natural gas salt cavern storage facilities in southeast Texas and Louisiana. MHP markets natural gas storage services to pipelines, LDCs, producers, end users and natural gas marketers. Texas Eastern and East Tennessee Natural Gas, LLC (ETNG) also provide firm and interruptible open-access storage services. Storage is offered as a stand-alone unbundled service or as part of a no-notice bundled service with transportation.
Natural Gas Transmission provides retail distribution services through its subsidiary, Union Gas Limited (Union Gas). Union Gas owns and operates natural gas transmission, distribution and storage facilities in Ontario. Union Gas distributes natural gas to approximately 1.2 million residential, commercial and industrial customers in northern, southwestern and eastern Ontario and provides storage, transportation and related services to utilities and other industry participants in the gas markets of Ontario, Quebec and the central and eastern United States.
Natural Gas Transmission’s processing plants in western Canada provide services primarily to natural gas producers to remove impurities from the raw gas stream including water, carbon dioxide, hydrogen sulphide and
other substances. In addition, where required the facilities remove liquid hydrocarbons including propane, butane and pentanes plus. Natural Gas Transmission receives a volume based fee for these processing services under contracts that have an average duration of one to three years.
In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to cause a Duke Capital subsidiary to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. Upon closing of this transaction, Natural Gas Transmission expects to receive Canadian assets being transferred from DEFS and assets in Alberta and Saskatchewan, Canada from ConocoPhillips, which will allow Natural Gas Transmission to continue building scope, scale and diversity within its Canadian asset portfolio.
Competition
Natural Gas Transmission’s transportation, storage and gas gathering and processing businesses compete with other pipeline and storage facilities that serve its market areas in the transportation, processing and storage of natural gas. The principal elements of competition are rates, terms of service, and flexibility and reliability of service.
Natural gas competes with other forms of energy available to Natural Gas Transmission’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors affect the demand for natural gas in the areas served by Natural Gas Transmission.
Union Gas’ distribution sales to industrial customers are affected by weather, economic conditions and the price of competitive energy sources. Most of Union Gas’ industrial and commercial customers, and a portion of residential customers, purchase their natural gas supply directly from suppliers or marketers. Because Union Gas earns income from the distribution of natural gas and not the sale of the natural gas commodity, the gas distribution margin is not affected by the source of the customer’s gas supply.
Regulation
Most of Natural Gas Transmission’s pipeline and storage operations in the U.S. are regulated by the FERC. The FERC has authority to regulate rates and charges for natural gas transported or stored for U.S. interstate commerce or sold by a natural gas company via interstate commerce for resale. (For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters-Natural Gas Transmission.”) The FERC also has authority over the construction and operation of U.S. pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities. In addition, certain operations are subject to state regulatory commissions.
FERC regulations restrict access to U.S. interstate pipeline natural gas transmission customer data by marketing and other energy affiliates, and place certain conditions on services provided by the U.S. interstate pipelines to their affiliated gas marketing entities. These regulations affect the activities of non-regulated affiliates with Natural Gas Transmission.
The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of these regulatory changes is to promote competition among the various sectors of the natural gas industry.
Natural Gas Transmission’s U.S. operations are subject to the jurisdiction of the EPA and state environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.) Natural Gas Transmission’s interstate natural gas pipelines are subject to the regulations of the DOT concerning pipeline safety. DOT regulations have incorporated certain provisions of the Natural Gas Pipeline Safety Act of 1968 (and subsequent acts). The DOT developed new regulations, effective February 14, 2004, that establish mandatory inspections for all natural gas transmission pipelines in high-consequence areas within 10 years. These regulations require pipeline operators to implement integrity management programs, including more frequent inspections, and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to life and property. Management believes that compliance with these DOT regulations for Natural Gas Transmission will not have a material adverse effect on the consolidated results of operations, cash flows or financial position of Duke Capital.
The natural gas gathering, processing, transmission, storage and distribution operations in Canada are subject to regulation by the NEB and provincial agencies in Canada, such as the OEB. These agencies have authorization similar to the FERC for regulating rates, regulating the operations of facilities and construction of any additional facilities.
FIELD SERVICES
Field Services gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, trades and markets, and stores NGLs. It conducts operations primarily through DEFS, which is approximately 30% owned by ConocoPhillips and approximately 70% owned by Duke Capital. In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to cause a Duke Capital subsidiary to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. Upon closing of this transaction, DEFS expects to transfer its Canadian assets to Duke Capital’s Natural Gas Transmission segment and receive certain U.S. Midstream assets or cash from ConocoPhillips. Upon completion of this transaction, DEFS will be owned 50% by Duke Capital and 50% by ConocoPhillips. As a result, Duke Capital expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction. This transaction, which is subject to customary U.S. and Canadian regulatory approvals, is expected to close in the latter half of 2005. Additionally, in February 2005, DEFS sold its wholly-owned subsidiary, TEPPCO, the general partner of TEPPCO Partners, L.P., for approximately $1.1 billion and Duke Capital sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to EPCO, an unrelated third party.
Field Services gathers raw natural gas through gathering systems located in eight major natural gas producing regions: Permian Basin, Mid-Continent, ArklaTex, Gulf Coast, South, Central, Rocky Mountains and Western Canada. Field Services owns and operates approximately 59,000 miles of gathering and transmission pipe, with approximately 34,000 active receipt points.
Field Services’ natural gas processing operations separate raw natural gas that has been gathered on its own systems and third-party systems into condensate, NGLs and residue gas. Field Services processes the raw natural gas at 57 natural gas processing facilities that it owns and operates and at nine third-party operated facilities in which it has an equity interest.
The NGLs separated from the raw natural gas are either sold and transported as NGL raw mix, or further separated through a fractionation process into their individual components (ethane, propane, butanes and natural gasoline) and then sold as components. Field Services fractionates NGL raw mix at ten processing facilities that it owns and operates and at four third-party-operated facilities in which it has an equity interest. In addition, Field Services operates a propane wholesale marketing business. Field Services sells NGLs to a variety of customers ranging from large, multinational petrochemical and refining companies to small regional retail propane distributors. Substantially all of its NGL sales are at market-based prices.
The residue gas separated from the raw natural gas is sold at market-based prices to marketers and end-users, including large industrial customers and natural gas and electric utilities serving individual consumers. Field Services markets residue gas directly or through its wholly owned gas marketing company and its affiliates. Field Services also stores residue gas at its 6 billion-cubic-foot (Bcf) natural gas storage facility.
Field Services uses NGL trading and storage at the Mont Belvieu, Texas and Conway, Kansas NGL market centers to manage its price risk and to provide additional services to its customers. Asset-based gas trading and marketing activities are supported by ownership of the Spindletop storage facility and various intrastate pipelines which provide access to market centers/hubs such as Katy, Texas, and the Houston Ship Channel. Field Services undertakes these NGL and gas trading activities through the use of fixed forward sales, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. Field Services believes there are additional opportunities to grow its services with its customer base.
The following map includes Field Services’ natural gas gathering systems, intrastate pipelines, regional offices and supply areas. The map also shows Natural Gas Transmission’s interstate pipeline systems.
Field Services’ operating results are significantly impacted by changes in average NGL prices, which increased approximately 28% in 2004 compared to 2003. Field Services closely monitors the risks associated with these price changes, using NGL and crude forward contracts to mitigate the effect of such fluctuations on operating results. (See “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk” for a discussion of Field Services’ exposure to changes in commodity prices.)
Competition
In gathering and processing natural gas and in marketing and transporting natural gas and NGLs, Field Services competes with major integrated oil companies, major interstate and intrastate pipelines, national and local natural gas gatherers, and brokers, marketers and distributors of natural gas supplies. Competition for natural gas supplies is based primarily on the reputation, efficiency and reliability of operations, the availability of gathering and transportation to high-demand markets, the pricing arrangement offered by the gatherer/processor and the ability of the gatherer/processor to obtain a satisfactory price for the producer’s residue gas and extracted NGLs. Competition for sales to customers is based primarily upon reliability, services offered, and price of delivered natural gas and NGLs.
Regulation
The intrastate natural gas and NGL pipelines owned by Field Services are subject to state regulation. To the extent that the natural gas intrastate pipelines provide services under Section 311 of the Natural Gas Policy Act
of 1978, they are also subject to FERC regulation. The interstate natural gas pipeline owned and operated by Field Services is subject to FERC regulation, but its natural gas gathering and processing activities are not subject to FERC regulation.
Field Services is subject to the jurisdiction of the EPA and state environmental agencies. (For more information, see “Environmental Matters” in this section.) Field Services’ natural gas transmission pipelines and some gathering pipelines are subject to the regulations of the DOT, and in some cases, state agencies, concerning pipeline safety. DOT regulations have incorporated certain provisions of the Natural Gas Pipeline Safety Act of 1968 (and subsequent acts). The DOT has developed new regulations, effective February 14, 2004, that establish mandatory inspections for all natural gas transmission pipelines in high-consequence areas within ten years, with reassessments at prescribed intervals thereafter. The new regulations require pipeline operators to implement integrity management programs, including more frequent inspections, and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to life and property, Management believes that compliance with these new DOT regulations will not have a material adverse effect on the consolidated results of operations, cash flows or financial position of Duke Capital.
Field Services’ Canadian assets are regulated by the Alberta Energy and Utilities Board and the NEB.
DENA
DENA operates and manages power plants and markets electric power and natural gas related to these plants and other contractual positions. DENA conducts business throughout the U.S. and Canada through Duke Energy North America, LLC and its 100% owned affiliates Duke Energy Marketing America, LLC and Duke Energy Marketing Canada Corp. DENA also participates in DETM. DETM is 40% owned by ExxonMobil Corporation and 60% owned by Duke Capital. The following summarizes certain key events from 2004.
•
Sold eight natural gas-fired merchant power plants: Hot Spring (Arkansas); Murray and Sandersville (Georgia); Marshall (Kentucky); Hinds, Southaven, Enterprise and New Albany (Mississippi) in the southeastern United States; and certain other power and gas contracts (collectively, the Southeast Plants)
•
Sold partially completed power plants in Nevada (Moapa) and New Mexico (Luna)
•
Signed an agreement for the sale of the partially completed Grays Harbor power plant in Washington state
•
Settled its Enron Corporation (Enron) bankruptcy proceedings and the majority of its California and Western U.S. energy markets issues, and
•
Executed re-organization efforts, resulting in significant staff and annual cost reductions.
Generation Assets
DENA currently owns or operates approximately 9,890 net MW of operating generation. In August 2004, DENA completed the sale of the Southeast Plants. DENA also completed the sales of its partially completed power plants in Moapa, Nevada in October 2004 and Luna, New Mexico in November 2004. DENA also entered into an agreement in December 2004 to divest of its interests in the partially completed Grays Harbor (Washington) power plant and associated contracts. (See Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions” for further discussion.)
On September 21, 2004, DENA signed a purchase and sale agreement to sell DENA’s 75% interests in Bayside Power L.P. (See Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale,” for further discussion.)
The following map shows DENA’s power generation facilities.
Marketing Portfolio
Much of DENA’s portfolio of purchase and sales agreements incorporate market-sensitive pricing terms. To minimize the impact of changing market conditions to DENA, physical purchases and sales are generally hedged with financial derivatives. Additionally, DENA continues to sell fixed capacity contracts in addition to volume based sales and purchases. (For information concerning DENA’s risk-management activities, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk” and Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)
DENA is active in the Western (California and Southwest), Northeast and Midwest power markets including the associated gas supply, transport and storage in those markets. DENA has a strong focus on increasing its percentage of contracted energy ($/MWh) and capacity ($/kW/month) versus energy/capacity sold into the spot/non-contracted markets. Additionally, DENA continues to sell fixed capacity contracts in addition to volume based sales and purchases.
Competition
The price of commodities and services, along with the quality and reliability of services provided, drive competition in the energy marketing business. DENA’s competitors include the following: utilities, financial institutions and hedge funds engaged in commodity trading, major interstate pipelines and their marketing affiliates, marketers and distributors, major integrated oil companies, other merchant electric generation companies in North America, brokers, and other domestic and international electric power and natural gas marketers.
Regulation
DENA’s energy marketing activities are subject to the jurisdiction of the FERC in some circumstances. Current FERC policies permit DENA’s trading and marketing entities to market natural gas, electricity and other energy-related commodities at market-based rates. Ongoing regulatory initiatives at both state and federal levels addressing market design, such as the development of capacity markets and real-time electricity markets, impact financial results from DENA’s marketing and generation activities.
Litigation at the state level is ongoing related to DENA’s activities in California during the electricity supply situation in 2000 and 2001. (See Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies-Litigation,” for further discussion.)
The operation and maintenance of DENA’s power plants in California are now subject to regulation pursuant to guidelines recently promulgated by state authorities. The new guidelines are intended to increase the reliability of the generation supply in California by setting operating and maintenance standards and regulating when plants may be taken out of service for routine maintenance. Duke Capital does not believe that the new guidelines will have a material impact on the operation of its power plants in California.
DENA is subject to the jurisdiction of the EPA and state environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)
INTERNATIONAL ENERGY
International Energy operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. and Canada. It conducts operations primarily through DEI and its activities target power generation in Latin America. Additionally, International Energy owns an equity investment in National Methanol Company, located in Saudi Arabia, which is a leading regional producer of methanol and MTBE.
International Energy’s customers include retail distributors, electric utilities, independent power producers, marketers and large industrial companies. International Energy is committed to building integrated regional businesses that provide customers with a full range of innovative and competitively priced energy services.
International Energy’s current strategy is focused on maximizing the returns and cash flow from its current portfolio of energy businesses by creating organic growth through its sales and marketing efforts in all regions in which it currently does business, optimizing the output and efficiency of its various facilities and controlling and reducing costs.
International Energy owns, operates or has substantial interests in approximately 4,139 net MW of generation facilities. The following map shows the locations of International Energy’s facilities, including projects under construction and non-generation facilities in Mexico and Saudi Arabia. The capacities shown in the map are gross MW values (for net MW values see “Properties-International Energy”).
During 2004, Duke Capital completed the sale of the Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business) to Alinta Ltd. All gains related to this transaction and the results of operations for these assets are included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations. (See Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale,” for further discussion.)
Also in 2004, International Energy completed the sale of its 30% equity interest in Compañia de Nitrógeno de Cantarell, S.A. de C.V. (Cantarell) a nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico. (See Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions,” for further discussion.)
Competition and Regulation
International Energy’s sales and marketing of electric power and natural gas competes directly with other generators and marketers serving its market areas. Competitors are country and region-specific but include government owned electric generating companies, LDC’s with self-generation capability and other privately owned electric generating companies. The principal elements of competition are price and availability, terms of service, flexibility and reliability of service.
A high percentage of International Energy’s portfolio consists of base-load hydro electric generation facilities which compete with other forms of electric generation available to International Energy’s customers and end-users, including natural gas and fuel oils. Economic activity, conservation, legislation, governmental regulations, weather and other factors affect the supply and demand for electricity in the regions served by International Energy.
International Energy’s operations are subject to both country-specific and international laws and regulations. (See “Environmental Matters” in this section.)
CRESCENT
Crescent develops and manages high-quality commercial, residential and multi-family real estate projects, and manages land holdings, primarily in the southeastern and southwestern U.S. As of December 31, 2004, Crescent owned 0.5 million square feet of commercial, industrial and retail space, with an additional 1.2 million square feet under construction. This portfolio included 0.9 million square feet of office space, 0.5 million square feet of warehouse space and 0.3 million square feet of retail space. Crescent’s residential developments include high-end country club and golf course communities, with individual lots sold to custom builders and tract developments sold to national builders. Crescent had three multi-family communities at December 31, 2004, including one operating property and two properties under development. As of December 31, 2004, Crescent also managed approximately 132,000 acres of land.
Competition and Regulation
Crescent competes with multiple regional and national real estate developers across its various business lines in the southeastern and southwestern U.S. Crescent’s residential division sells developed lots to regional and national home builders and retail buyers, competing with other developers and home builders who have inventories of developed lots. Crescent’s commercial division leases office, industrial and retail space, competing with other public and private developers and owners of commercial property, including national real estate investment trusts (REITs). Similarly, Crescent’s multi-family division leases apartment units primarily to individuals, competing with other private developers and multi-family REITs.
Crescent is subject to the jurisdiction of the EPA and state and local environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)
OTHER
During 2004, Other primarily included certain unallocated corporate costs, DukeNet, Duke Capital’s 50% interest in D/FD, and Bison. DCP had been previously included in Other, however at December 31, 2004 Duke Capital had exited the merchant finance business, and all of the results of operations for DCP for the years ended December 31, 2004, 2003 and 2002 have been classified as discontinued operations.
DukeNet develops, owns and operates a fiber optic communications network, primarily in the Carolinas, serving wireless, local and long-distance communications companies, Internet service providers and other businesses and organizations.
D/FD is a 50/50 partnership between subsidiaries of Duke Capital and Fluor Corporation. During 2003, Duke Capital and Fluor Corporation announced that they would dissolve the D/FD partnership. The D/FD partners adopted a plan for an orderly wind-down of the business which is expected to be completed by December 2005. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide.
Bison’s principle activities, as a captive insurance entity, include the insurance and reinsurance of various business risks and losses, such as workers compensation, property, business interruption, and general liability of subsidiaries and affiliates of Duke Capital. Bison also participates in reinsurance activities with certain third parties, on a limited basis.
Competition and Regulation
The entities within Other are subject to the jurisdiction of the EPA and state and local environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)
ENVIRONMENTAL MATTERS
Duke Capital is subject to international, federal, state and local laws and regulations with regard to air and water quality, hazardous and solid waste disposal and other environmental matters. Environmental laws and regulations affecting Duke Capital include, but are not limited to:
•
The Clean Air Act and the 1990 amendments to the Act, as well as state laws and regulations impacting air emissions, including State Implementation Plans related to existing and new national ambient air quality standards for ozone and particulate matter. Owners and/or operators of air emission sources are responsible for obtaining permits and for annual compliance and reporting.
•
The Federal Water Pollution Control Act which requires permits for facilities that discharge wastewaters into the environment.
•
The Comprehensive Environmental Response, Compensation and Liability Act, which can require any individual or entity that currently owns or in the past may have owned or operated a disposal site, as well as transporters or generators of hazardous substances sent to a disposal site, to share in remediation costs.
•
The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, which requires certain solid wastes, including hazardous wastes, to be managed pursuant to a comprehensive regulatory regime.
•
The National Environmental Policy Act, which requires federal agencies to consider potential environmental impacts in their decisions, including siting approvals.
(For more information on environmental matters involving Duke Capital, including possible liability and capital costs, see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies-Environmental.”)
Except to the extent discussed in Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” and Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies,” compliance with international, federal, state and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is not expected to have a material adverse effect on the competitive position, consolidated results of operations, cash flows or financial position of Duke Capital.
GEOGRAPHIC REGIONS
For a discussion of Duke Capital’s foreign operations and the risks associated with them, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk-Foreign Currency Risk,” and Notes 3 and 7 to the Consolidated Financial Statements, “Business Segments” and “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”
EMPLOYEES
On December 31, 2004, Duke Capital had approximately 11,700 employees. A total of 1,998 operating, and maintenance employees were represented by unions. This amount consists of the following:
•
1,108 employees represented by the Communications, Energy and Paperworkers of Canada
•
208 employees represented by the Canadian Pipeline Employees Association
•
156 employees represented by the International Brotherhood of Electrical Workers
•
154 employees represented by the United Steelworkers of America
•
79 employees represented by Sindicato de Trabajadores del Sector Electrico
•
75 employees represented by the International Union of Operating Engineers
•
70 employees represented by Sindicato dos Trabalhadores na Industria da Energia Hidroeletrica de Ipaussu
•
38 employees represented by Sindicato Unico de Centrales de Generacion Electrica-Canon del Pato
•
29 employees represented by Asociacion del Personal Jerarquico del Agua y la Energia
•
24 employees represented by Sindicato dos Trabalhadores na Industria de Energia Eletrica de Campinas
•
20 employees represented by Sindicato Corani
•
15 employees represented by Sindicato Unico de Generacion Electrica-Carhuaquero
•
13 employees represented by Federacion Argentina de Trabajadores de Luz y Fuerza
•
7 employees represented by Sindicato dos Trabalhadores nas Industrias de Energia Eletrica de Sao Paulo
•
2 employees represented by the United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industries of the U.S. and Canada
Item 2.
Item 2. Properties.
NATURAL GAS TRANSMISSION
Texas Eastern’s gas transmission system extends approximately 1,700 miles from producing fields in the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New Jersey and New York. It consists of two parallel systems, one with three large-diameter parallel pipelines and the other with one to three large-diameter pipelines. Texas Eastern’s onshore system consists of approximately 8,600 miles of pipeline and 73 compressor stations.
Texas Eastern also owns and operates two offshore Louisiana pipeline systems, which extend approximately 100 miles into the Gulf of Mexico and include approximately 500 miles of Texas Eastern’s pipeline system.
Texas Eastern has two joint-venture storage facilities in Pennsylvania and one wholly owned and operated storage field in Maryland. Texas Eastern’s total working capacity in these three fields is 75 Bcf.
Algonquin transmission system connects with Texas Eastern’s facilities in New Jersey, and extends approximately 250 miles through New Jersey, New York, Connecticut, Rhode Island and Massachusetts. The system consists of approximately 1,100 miles of pipeline with six compressor stations.
ETNG’s transmission system crosses Texas Eastern’s system at two points in Tennessee and consists of two mainline systems totaling approximately 1,400 miles of pipeline in Tennessee, Georgia, North Carolina and Virginia, with 18 compressor stations.
ETNG has an LNG storage facility in Tennessee with a total working capacity of 1.2 Bcf.
Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively, Maritimes & Northeast) transmission system (approximately 78% owned by Duke Capital) extends approximately 900 miles from producing fields in Nova Scotia through New Brunswick, Maine, New Hampshire and Massachusetts, connecting to Algonquin in Beverly, Massachusetts. It has two compressor stations on the system.
The British Columbia Pipeline System consists of two divisions. The field services division operates more than 1,840 miles of gathering pipelines in British Columbia, Alberta, the Yukon Territory and the Northwest Territories, as well as 22 field compressor stations; four gas processing plants located in British Columbia near Fort Nelson, Taylor, Chetwynd and in the Sikanni area northwest of Fort St. John, and three elemental sulphur recovery plants located at Fort Nelson, Taylor and Chetwynd. Total contractible capacity is approximately 1.8 Bcf of residue gas per day. The pipeline division has approximately 1,740 miles of transmission pipelines in British Columbia and Alberta, as well as 18 mainline compressor stations.
Union Gas owns and operates natural gas transmission, distribution and storage facilities in Ontario. Union Gas’ distribution system consists of approximately 22,000 miles of distribution pipelines. Union Gas’ underground natural gas storage facilities have a working capacity of approximately 150 Bcf in 20 underground facilities located in depleted gas fields. Its transmission system consists of approximately 3,000 miles of pipeline and six mainline compressor stations.
MHP owns and operates two natural gas storage facilities, Moss Bluff and Egan, with a total storage capacity of approximately 31 Bcf. The Moss Bluff facility consists of three storage caverns located in southeast Texas and has access to five pipeline systems. The Egan facility consists of three storage caverns located in south central Louisiana and has access to eight pipeline systems.
Natural Gas Transmission also has an investment in Gulfstream National Gas System, LLC (Gulfstream), a 691-mile interstate natural gas pipeline system owned and operated jointly by Duke Capital and The Williams Company, Inc. The Gulfstream gas pipeline has a capacity of 1.1 Bcf of natural gas per day and transports gas from the Mobile Bay area, across the Gulf of Mexico, to growing gas markets in south and central Florida. Gulfstream began initial service in May 2002.
(For a map showing natural gas transmission and storage properties, see “Business-Natural Gas Transmission” earlier in this section.)
FIELD SERVICES
(For information and a map showing Field Services’ properties, see “Business-Field Services” earlier in this section.)
DENA
The following table provides information about DENA’s generation portfolio in continuing operations as of December 31, 2004.
(For a map showing DENA’s properties, see “Business-DENA” earlier in this section.)
INTERNATIONAL ENERGY
The following table provides information about International Energy’s generation portfolio in continuing operations as of December 31, 2004.
In addition to those generating facilities, International Energy owns a 25% equity interest in National Methanol Company (NMC), located in Saudi Arabia, which is a leading producer of methanol and MTBE. In 2004, the NMC produced approximately 900 thousand metric tons of methanol and one million metric tons of MTBE. International Energy also owns a 50% equity interest in Compañía de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche), located in the Cantarell oil field in the Bay of Campeche, Mexico, which compresses and dehydrates natural gas and extracts NGLs. Campeche has an installed processing capacity of 270 Mmcf/d. (For additional information and a map showing International Energy’s properties, see “Business-International Energy” earlier in this section.)
CRESCENT
(For information regarding Crescent’s properties, see “Business-Crescent” earlier in this section.)
OTHER
(For information regarding the properties of the business unit now known as Other, see “Business-Other” earlier in this section.)
Item 3.
Item 3. Legal Proceedings.
In July 2003, a fire occurred at the Moss Landing Power Plant in California, operated by Duke Energy Moss Landing LLC (DEML), a subsidiary of DENA, when fuel oil was ignited by a contractor performing tank clean out and dismantling activities. The Monterey County District Attorney initiated civil enforcement action against DEML alleging violations of the California Health and Safety Code and the Business and Professions Code. The alleged violations concerned the handling of hazardous materials at the site and unlawful release of hazardous materials into the environment. DEML denied the allegations but agreed to settle the civil enforcement action by committing to expend a total of $752,287, the majority of which entails reimbursement of costs to the county and expenditures for safety/environmental training efforts by the company, but also includes a $100,000 civil penalty payment. The district attorney also settled a related action against DEML’s contractor for alleged violations in the incident. Both settlements were announced on September 22, 2004.
(For information regarding legal proceedings, including regulatory and environmental matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies-Litigation” and “Commitments and Contingencies-Environmental.”)
PART II.
Item 5.
Item 5. Market for Registrant’s Member’s/Common Equity and Related Stockholder Matters.
All of the outstanding limited liability company member interests of Duke Capital are owned by Duke Energy. There is no market for Duke Capital’s limited liability company member interest. Distributions on Duke Capital’s limited liability company member interests will be paid when declared by the Board of Directors. Duke Capital did not pay distributions on its member’s/common equity in 2004, 2003 or 2002. Duke Capital continues to review its policy with respect to paying future distributions and anticipates making periodic distributions over the next three years to facilitate Duke Energy’s stock repurchase program announced in February 2005.
On March 23, 2005, Duke Capital distributed $750 million to its parent, Duke Energy, to provide funding for the execution of Duke Energy’s accelerated share acquisition plan. The distribution was principally obtained from Duke Capital’s portion of the cash proceeds realized from the recent sale by DEFS of the general partner of TEPPCO Partners, L.P. and Duke Capital’s sale of its limited partner interests in TEPPCO Partners, L.P.
Item 6.
Item 6. Selected Financial Data.
(a)
As of January 1, 2003, Duke Capital adopted the remaining provisions of Emerging Issues Task Force Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities” and SFAS No. 143, “Accounting for Asset Retirement Obligations.” In accordance with the transition guidance for these standards, Duke Capital recorded a net-of-tax and minority interest cumulative effect adjustment for change in accounting principles. See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for further discussion.
(b)
Earnings were inadequate to cover fixed charges by $2,384 million for the year ended December 31, 2003.
Item 7.
Item 7. Management’s Discussion and Analysis of Results of Operations and Financial Condition.
INTRODUCTION
Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements.
Overview of Business Strategy. Duke Capital’s business strategy is to develop integrated energy businesses in targeted regions where Duke Capital’s capabilities in developing energy assets; operating power plants, natural gas liquid (NGL) plants and natural gas pipelines; optimizing commercial operations (including its affiliated real estate operation); and managing risk can provide comprehensive energy solutions for customers and create value for its parent company.
For the past few years, the energy industry including Duke Capital experienced a number of challenges, including the substantial imbalance between supply and demand for electricity, the pace of economic recovery, and regulatory and legal uncertainties. In response to these challenges, Duke Capital’s focus for 2004 was to reduce risks and restructure its business. By selling assets such as Duke Energy North America’s (DENA’s) eight natural gas-fired merchant power plants: Hot Spring (Arkansas); Murray and Sandersville (Georgia); Marshall (Kentucky); Hinds, Southaven, Enterprise and New Albany (Mississippi) in the southeastern United States; (collectively, the Southeast Plants) and International Energy’s Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business), Duke Capital eliminated some of its lowest return assets. These asset sales provided cash proceeds allowing Duke Capital to pay down debt and strengthen its balance sheet. Progress was also made in 2004 in resolving some critical legal and regulatory issues.
As a result of the efforts in 2004, Duke Capital’s objectives for 2005 include establishing industry-leading positions in core businesses and identifying new energy-related growth strategies, focused in the Americas. Increased demand for natural gas supplies in the United States and changing logistics among source of supply are providing opportunities for growth. To capitalize on this market dynamic, Natural Gas Transmission is evaluating longer-term opportunities to provide pipeline capacity and storage facilities for the expected expansion of the liquefied natural gas (LNG) market. Additionally, the strength of the natural gas market provides incentives for producers to increase exploration and production, which in turn, provides business sustainability and growth opportunities for Field Services. International Energy is expected to grow organically for the near term.
In February 2005, Duke Energy Field Services LLC (DEFS) sold Texas Eastern Products Pipeline Company LLC (TEPPCO) for approximately $1.1 billion and Duke Capital sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to EPCO, an unrelated third party. These transactions closed in the first quarter of 2005.
In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to cause a Duke Capital subsidiary to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. Upon completion of this transaction, DEFS will be owned 50% by Duke Capital and 50% by ConocoPhillips. As a result, Duke Capital expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction, which is expected to occur in the latter half of 2005.
Duke Capital believes merchant energy will play a vital role in meeting the United States’ energy demand. Another key objective for 2005 is to position DENA to be a successful merchant operator. During 2004, DENA’s business model changed to focus on selling fixed capacity contracts in addition to volume based sales and purchases. Duke Capital is pursuing various options to create a sustainable business model for DENA, including consideration of potential business partners. A sustainable business model will include fuel and geographic diversity, sufficient size and scope for a substantial market presence and will enable DENA to better withstand the cyclical nature of the industry. Depending on the option selected, there is a risk that material impairments or
losses could be recorded, including the potential disqualification of certain contracts and the recognition of unrealized losses associated with DENA power forward sales contracts designated under the normal purchases and normal sales exemption, which totaled approximately $900 million (pre-tax) as of December 31, 2004. This unrealized loss represents the difference in the normal purchases and normal sales contract prices compared to the forward market prices of power and is partially offset by unrealized gains on natural gas positions of approximately $800 million (pretax) as of December 31, 2004. (For more information see Commodity Price Risk discussion under Quantitative and Qualitative Disclosures About Market Risk).
With cash, cash equivalents and short-term investments on hand at December 31, 2004 of approximately $1.6 billion and a more stable business environment, Duke Capital has financial flexibility to invest incrementally or pay down additional debt. Duke Capital is evaluating these options and will determine the best economic decisions to ensure the long-term financial strength of Duke Capital.
Other key objectives for Duke Capital in 2005 are to build stakeholder relationships through effective leadership on key policy issues related to energy, regulation and the environment, and also to focus on safety, inclusion and diversity, employee development, business structure and process simplification.
Economic Factors for Duke Capital’s Business. Duke Capital’s business model provides diversification between stable, less cyclical businesses like Natural Gas Transmission, and the traditionally higher-growth and more cyclical energy businesses like DENA, International Energy and Field Services. Additionally, Crescent Resources LLC’s (Crescent’s) portfolio strategy is diversified between residential, commercial and multi-family development. All of Duke Capital’s businesses can be negatively affected by sustained downturns or sluggishness in the economy, including low market price of commodities, all of which are beyond Duke Capital’s control, and could impair Duke Capital’s ability to meet its goals for 2005 and beyond.
Natural Gas Transmission is subject to mandated tariff rates and recovery of certain fuel costs. Lower economic output would also cause the Natural Gas Transmission and Field Services businesses to experience a decline in the volume of natural gas shipped through their pipelines, gathered and processed at their plants, or distributed by their local distribution company, resulting in lower revenue and cash flows. Natural Gas Transmission continues to experience positive renewals of its customer contracts as they expire.
If negative market conditions persist over time and estimated cash flows over the lives of Duke Capital’s individual assets do not exceed the carrying value of those individual assets, asset impairments may occur in the future under existing accounting rules and diminish results of operations. Furthermore, a change in management’s intent about the use of individual assets (held for use versus held for sale) or a change in fair value of assets held for sale could also result in impairments or losses.
Duke Capital’s goals for 2005 can also be substantially at risk due to the regulation of its businesses. Duke Capital’s businesses in North America are subject to regulations on the federal and state level. The majority of Duke Capital’s Canadian natural gas assets is also subject to various degrees of federal or provincial regulation and is subject to the same risks. Regulations, applicable to the gas transmission and storage industry, have a significant impact on the nature of the businesses and the manner in which they operate. Changes to regulations are ongoing and Duke Capital cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on its business.
Additionally, Duke Capital’s investments and projects located outside of the United States expose it to risks related to laws of other countries, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. Changes in these factors are difficult to predict and may impact Duke Capital’s future results. Duke Capital’s recent restructuring, which focuses its non-United States operations on only Latin America and Canada, will help mitigate this exposure.
Duke Capital also relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not met by the cash flow from its operations. If Duke Capital is not
able to access capital at competitive rates, its ability to implement its strategy could be adversely affected. Market disruptions or a downgrade of Duke Capital’s credit rating may increase its cost of borrowing or adversely affect its ability to access one or more sources of liquidity.
RESULTS OF OPERATIONS
Overview of Drivers and Variances for 2004 and 2003
Year Ended December 31, 2004 as Compared to December 31, 2003. For 2004, Duke Capital had a net loss of $127 million, compared to a net loss of $1,798 million in 2003. Significant items that contributed to the improved results in 2004 included:
•
Pre-tax charges of $2.8 billion in 2003 related to asset impairments of: DENA’s Southeast Plants which were sold during 2004, DENA’s partially completed Western plants, two of which were sold in 2004 and wind-down costs associated with the Duke Energy Trading and Marketing LLC (DETM) joint venture
•
A $295 million pre-tax gain ($273 million net of tax) recorded in 2004 on the sale of International Energy’s Asia-Pacific Business, slightly offset by a loss on its European gas trading and marketing business (European Business)
•
Net pre-tax charges and impairments of $292 million ($223 million net of tax) in 2003 for International Energy’s Asia-Pacific and European Businesses, which were classified as discontinued operations and subsequently sold in 2004
•
Pre-tax charges of $262 million in 2003 for the disqualification of certain hedges and contracts that were being accounted for as normal purchases and normal sales from the Accrual Model to the MTM Model that were related to the impaired assets at DENA
•
A pre-tax charge of $254 million in 2003 for goodwill impairment at DENA, related primarily to the trading and marketing business
•
Pre-tax gains of $180 million on the sales of two partially completed plants at DENA in 2004
•
Charges in 2003 related to changes in accounting principles of $133 million, net of tax and minority interest
•
A $109 million (net of minority interest of $5 million) pre-tax gain in 2004 related to the settlement of the Enron bankruptcy proceedings
•
A $86 million tax benefit in 2004 related to the ongoing operations of certain realigned subsidiaries at Duke Capital, and the pass-through structure of these for U.S. income tax purposes (see Note 5 to the Consolidated Financial Statements, “Income Taxes”)
•
Pre-tax severance and related charges of $74 million in 2003 associated with workforce reductions across all segments, net of minority interest of $2 million
•
A $59 million pre-tax decrease in 2004 Operating Expenses as a result of the correction of an accounting error in prior periods related to reserves at Bison Insurance Company Limited (Bison) for property losses at several Duke Capital subsidiaries
•
The reduction of various income tax reserves in 2004 totaling approximately $52 million (see Note 5 to the Consolidated Financial Statements, “Income Taxes”)
•
A pre-tax charge of $51 million in 2003 for the write-off of an abandoned corporate risk management information system
•
Increased 2004 earnings at Field Services due to favorable effects of commodity prices and improved results from trading and marketing activities, and
•
Increased residential developed lot sales, commercial project and land management (“legacy” land sales) at Crescent, due to several large sales that closed in 2004.
Partially offsetting these increases and prior year charges were:
•
A $1,030 million one time tax expense in 2004 related to the realignment of certain subsidiaries of Duke Capital and the pass-through structure of these for U.S. income tax purposes (see Note 5 to the Consolidated Financial Statements, “Income Taxes”)
•
An approximate $360 million pre-tax charge in the first quarter of 2004 associated with the sale of DENA’s Southeast Plants (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”)
•
A $178 million pre-tax gain in 2003 from the sale of DENA’s 50% interest in Duke/UAE Ref-Fuel LLC (Ref-Fuel)
•
A $105 million pre-tax charge in 2004 related to the California and western U.S. energy markets settlement (see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies”), and
•
A $52 million income tax benefit in 2003 related to the write-off of goodwill at International Energy’s European Business in 2002.
For additional information on specific business unit related items, see the segment discussions that follow. For a detailed discussion of interest, taxes and the impact of changes in accounting principles, see “Other Impacts on Net (Loss) Income” at the end of this section.
Consolidated Operating Revenues
Year Ended December 31, 2004 as Compared to December 31, 2003. Consolidated operating revenues for 2004 increased $479 million, compared to 2003. This change was driven by:
•
A $304 million increase in Non-regulated Electric, Natural Gas, Natural Gas Liquids, and Other revenues due to higher average NGL and natural gas prices at Field Services, partially offset by the continued wind-down of DETM, and
•
A $175 million increase in Regulated Natural Gas revenues, due primarily to the strengthening Canadian dollar at Natural Gas Transmission.
Year Ended December 31, 2003 as Compared to December 31, 2002. Consolidated operating revenues for 2003 increased $4,994 million, compared to 2002. This change was primarily driven by:
•
A $4,252 million increase in Non-regulated Electric, Natural Gas, Natural Gas Liquids, and Other revenues, due primarily to increased NGL pricing and due to the adoption of the final consensus on Emerging Issues Task Force (EITF) Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities,” on January 1, 2003. As of that date, Duke Capital began to report revenues and expenses for certain derivative and non-derivative gas and other contracts on a gross basis instead of a net basis. Adopting the final consensus on EITF Issue No. 02-03 did not require a change to prior periods, which had already been changed in 2002 to report amounts on a net basis in accordance with earlier provisions of EITF Issue No. 02-03, and
•
A $742 million increase in Regulated Natural Gas revenues due primarily to increased transportation, storage and distribution revenues from assets acquired or consolidated as a part of the acquisition of Westcoast Energy Inc. (Westcoast) in March 2002.
Consolidated Operating Expenses
Year Ended December 31, 2004 as Compared to December 31, 2003. Consolidated operating expenses for 2004 decreased $3,036 million, compared to 2003. The change was primarily driven by:
•
A $2,888 million decrease in Impairments and Other Related Charges due primarily to charges of $2,903 million in 2003 resulting from strategic actions taken at DENA which led to the recording of impairments related to the Southeast Plants, partially completed plants, disqualified hedges and normal purchases and sales contracts, offset by $65 million of impairments in 2004 at Field Services and Crescent
•
A $141 million decrease in Operation, Maintenance and Other due primarily to severance costs accrued in 2003 related to workforce reductions and decreased operating and maintenance cost at DENA resulting from cost reduction efforts and the sale of plants in 2004, partially offset by increased costs at Crescent related to increased residential developed lot sales, and
•
A $254 million decrease due to the 2003 write off of goodwill at DENA, most of which related to DENA’s trading and marketing business.
Year Ended December 31, 2003 as Compared to December 31, 2002. Consolidated operating expenses for 2003 increased $8,053 million, compared to 2002. The increase in consolidated operating expenses was driven primarily by impairments and other related charges, as discussed above, and by the same drivers that affected consolidated operating revenues: increased purchase costs for NGLs, the adoption of the final consensus on EITF Issue No. 02-03, and additional expenses due to the acquisition of Westcoast.
Consolidated Gains on Sales of Investments in Commercial and Multi-Family Real Estate
Consolidated gains on sales of investments in commercial and multi-family real estate were $192 million in 2004, $84 million in 2003, and $106 million in 2002. For a detailed discussion of this item see the Crescent segment discussion below.
Consolidated Losses on Sales of Other Assets, net
Consolidated losses on sales of other assets, net were $240 million for 2004 and $203 million for 2003. The loss in 2004 was due primarily to pre-tax losses on the sale of the Southeast Plants (approximately $360 million) at DENA and the termination and sale of DETM contracts ($65 million) offset by gains on the sales of two partially completed plants, Moapa ($140 million) and Luna ($40 million) at DENA. The loss for 2003 was primarily comprised of a $208 million loss at DENA primarily related to charges on DETM contracts ($127 million) resulting from the wind-down of DETM’s operations, and impairments recorded on assets held for sale, including a 25% undivided interest in the wholly-owned Vermillion facility ($18 million) and stored turbines and related equipment ($66 million).
Consolidated Operating Income
Year Ended December 31, 2004 as Compared to December 31, 2003. For 2004, consolidated operating income increased $3,586 million, compared to 2003. Increased operating income was driven primarily by increased operating income at DENA, as a result of impairments and other related charges in 2003.
Year Ended December 31, 2003 as Compared to December 31, 2002. For 2003, consolidated operating income decreased $3,284 million, compared to 2002. Lower operating income was driven primarily by asset impairments and related charges at DENA of $2,903 million, as discussed above.
Consolidated Other Income and Expenses
Consolidated other income and expenses decreased $241 million for the year ended December 31, 2004 as compared to December 31, 2003. The decrease primarily resulted from the $178 million pre-tax gain on the sale
of DENA’s 50% interest in Ref-Fuel in 2003 and Natural Gas Transmission’s $90 million gain on sales of various investments in 2003, offset by foregone earnings from those investments. The increase in 2003 compared to 2002 was also a result of the gain from the Ref-Fuel sale as discussed above.
Segment Results
Management evaluates segment performance primarily based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT). On a segment basis, EBIT represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. EBIT excludes discontinued operations. Cash, cash equivalents and short-term investments are managed centrally by Duke Capital, so the gains and losses on foreign currency remeasurement associated with cash balances and interest income on those balances are excluded from the segments’ EBIT. Management considers segment EBIT to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of Duke Capital’s ownership interest in operations without regard to financing methods or capital structures.
Duke Capital’s segment EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner. Business segment EBIT is summarized in the following table, and detailed discussions follow.
EBIT by Business Segment
(a)
Includes interest income, foreign currency remeasurement gains and losses, additional minority interest expense not allocated to the segment results and intersegment eliminations.
The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements.
Natural Gas Transmission
(a)
Trillion British thermal units. Revenues are not significantly impacted by pipeline throughput fluctuations since revenues are primarily composed of demand charges.
Year Ended December 31, 2004 as Compared to December 31, 2003
Operating Revenues. The increase was driven primarily by:
•
A $171 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses)
•
A $62 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices that are passed through to customers without a mark-up at Union Gas Limited (Union Gas). This revenues increase is offset in expenses.
•
A $40 million increase from completed and operational pipeline expansion projects in the United States, partially offset by
•
A $95 million decrease as a result of the sale of Empire State Pipeline in February 2003 and Pacific Natural Gas (PNG) in December 2003, and
•
An $80 million decrease in gas distribution revenues at Union Gas resulting from lower gas usage in the power market due to unfavorable weather.
Operating Expenses. The increase was driven primarily by:
•
A $124 million increase caused by foreign exchange impacts (offset by currency impacts to revenues)
•
A $62 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues.
•
A $52 million increase resulting from the favorable resolution in 2003 of various contingencies primarily related to a capital project and outstanding ad valorem and franchise tax issues from prior state audits
•
A $17 million increase associated with the pipeline expansion projects placed in service
•
A $14 million increase in depreciation primarily due to an increase in the depreciation rate and the addition of two major projects in the Western Canadian operations, partially offset by
•
An $80 million decrease as a result of operations sold in 2003 as discussed above
•
A $63 million decrease in the cost of gas sold for distribution at Union Gas, due primarily to reduced volumes
•
A $29 million decrease due to severance costs in 2003, and
•
A $23 million decrease primarily related to the 2004 resolution of ad valorem tax issues in various states.
Other Income, net of expenses. The decrease was driven primarily by:
•
A $90 million decrease as a result of prior year gains on sales, primarily the gain on the sale of Natural Gas Transmission’s interests in Northern Border Partners L.P. in January 2003, Alliance Pipeline and the Aux Sable liquids plants in April 2003, and Foothills Pipe Lines Ltd in August 2003
•
A $22 million decrease in AFUDC (equity component) due to lower capital spending in 2004
•
An $18 million decrease in equity earnings as a result of investments sold in 2003, partially offset by
•
A $36 million increase resulting from the 2003 negative settlement of hedges related to foreign currency exposure
•
An increase of $16 million in equity earnings of Gulfstream Natural Gas System LLC (Gulfstream), resulting from higher revenues and volumes due to fuel switching during the unusually active hurricane season in Florida in 2004, and
•
A $16 million increase from 2004 gains on the sale of equity investments, primarily due to resolution of contingencies related to prior year sales.
Minority Interest Expenses. The decrease was driven primarily by the sale of PNG in December 2003, as well as lower earnings on Maritimes & Northeast Pipeline.
EBIT. EBIT decreased primarily as a result of gains from sales of equity investments recorded in the prior year and foregone earnings from the investments sold. Those decreases were mostly offset by earnings from expansion projects and foreign exchange EBIT impacts from the strengthening Canadian currency.
Matters Impacting Future Natural Gas Transmission Results
Natural Gas Transmission plans to continue earnings growth through capital efficient expansions in existing markets, optimization of existing systems, and organizational efficiencies and cost control. Natural Gas Transmission expects modest annual EBIT growth over the next three years from its 2004 EBIT, generally consistent with growth in demand. Demand for natural gas is expected to grow two to three percent in DEGT’s key markets. The average contract life for the U.S. pipelines is eight years. Changes in the Canadian dollar, weather, throughput and the ability to renew service contracts would impact future financial results at Natural Gas Transmission.
In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to cause a Duke Capital subsidiary to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. Upon closing of this transaction, DEFS expects to transfer its Canadian assets to Duke Capital’s Natural Gas Transmission segment. Also as part of this transaction, Natural Gas Transmission expects to receive assets in Alberta, Canada from ConocoPhillips. This transaction, which is subject to customary U.S. and Canadian regulatory approval, is expected to close in the latter half of 2005.
Year Ended December 31, 2003 as Compared to December 31, 2002
Operating Revenues. This increase was driven primarily by:
•
A $466 million increase in transportation, storage and distribution revenue in January and February 2003 from assets acquired or consolidated as a part of the Westcoast acquisition in March 2002 (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”)
•
A $177 million increase due to foreign exchange favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses)
•
An $81 million increase from recovery of natural gas commodity costs that are passed through to customers without a mark-up at Union Gas. This amount is offset by a corresponding increase in expenses.
•
A $31 million increase from completed and operational business expansion projects in the U.S., partially offset by
•
A $58 million decrease from operations sold in 2003 and the fourth quarter of 2002.
Operating Expenses. This increase was driven primarily by:
•
A $319 million increase in transportation, storage, and distribution expenses in January and February 2003 from assets acquired or consolidated as a part of the Westcoast acquisition in March 2002
•
A $132 million increase caused by foreign exchange impacts (partially offset by currency impacts to revenues)
•
An $81 million increase related to increased natural gas prices at Union Gas. This amount is offset by a corresponding increase in revenues.
•
A $20 million increase from 2003 severance charges related to workforce reductions, partially offset by
•
A $38 million decrease from operations sold in the fourth quarter of 2002 and in 2003.
For the year ended December 31, 2003, Natural Gas Transmission’s operating expenses increased approximately 39% when compared to the same period in 2002, while operating revenues increased approximately 30%. The difference was due to the Westcoast operations that were acquired in March 2002. The operating expenses, as a percentage of operating revenues, of the acquired Westcoast natural gas distribution business, are greater than the previously owned natural gas transmission business. Gas commodity costs related to the Westcoast distribution business are recovered from customers by increasing revenues by the amount of gas commodity costs expensed (i.e. flowed through to customers with no incremental profit).
Other Income, net of expenses. This decrease was driven primarily by:
•
A $36 million decrease from negative foreign exchange impacts in 2003, due to the settlement of hedges related to foreign currency exposure
•
A $33 million decrease in equity earnings associated with the sold investments
•
A $28 million decrease due to a construction fee received in 2002 from an affiliate related to the successful completion of Gulfstream, 50% owned by Duke Capital which went into service in May 2002, partially offset by
•
A $58 million increase in gains from the sale of various equity investments in 2003, and
•
A $17 million increase in AFUDC related to additional capital projects.
Minority Interest Expense. Minority interest expense increased in 2003 compared to 2002. This resulted from the recognition of a full year of minority interest expense in 2003, versus only ten months during 2002, from less than wholly owned subsidiaries acquired in the March 2002 acquisition of Westcoast.
EBIT. EBIT increased in 2003 compared to 2002, due primarily to incremental EBIT related to assets acquired or consolidated as part of the March 2002 acquisition of Westcoast, gains on asset sales, and business expansion projects in the U.S. These items were partially offset by earnings in 2002 from operations that were sold in the fourth quarter of 2002 and during 2003, and 2003 severance charges in excess of 2002 amounts.
Field Services
(a)
Trillion British thermal units per day
(b)
Thousand barrels per day
(c)
Million British thermal units
(d)
Does not reflect results of commodity hedges
Year Ended December 31, 2004 as Compared to December 31, 2003
Operating Revenues. The increase was primarily driven by:
•
A $870 million increase due primarily to a $0.15 per gallon increase in average NGL prices
•
A $590 million increase due primarily to a $0.75 per MMBtu increase in average natural gas prices
•
A $51 million increase from trading and marketing net margin, due primarily to natural gas asset based trading and marketing price volatility
•
A $45 million increase attributable to a $10.29 per barrel increase in average condensate prices to $41.37 during 2004 from $31.08 during 2003
•
A $35 million increase related to higher transportation, storage and processing fees which was primarily due to higher fees from processing contracts, partially offset by
•
A $44 million decrease related to the impact of cash flow hedging, which reduced revenues by approximately $242 million for the year ended December 31, 2004 and by $198 million for the year ended December 31, 2003, as compared to what revenue would have been without any hedging, and
•
A $30 million decrease related to lower NGL and raw natural gas sales volume, partially offset by an increase in wholesale propane marketing activity primarily due to higher propane prices, and the acquisition of gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips (COP Acquisition). Although production volumes increased as a result of processing economics and the COP Acquisition, sales volumes decreased as a result of producers marketing their NGLs on their own behalf.
Operating Expenses. The increase was driven primarily by:
•
A $1,175 million increase due to higher average costs of raw natural gas supply which was due primarily to an increase in average NGL and natural gas prices
•
A $18 million increase related to impairment charges associated with a planned shut down of a specific plant and a disposal of certain assets
•
A $20 million increase related primarily to an increase in wholesale propane marketing activity and the acquisition of gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips partially offset by lower purchased raw natural gas supply volume, partially offset by
•
A $25 million decrease in operating, and general and administrative expenses, primarily due to severance charges and other employee related expenditures in 2003 not experienced in 2004, lower repairs and maintenance, and environmental expenses in 2004, partially offset by an increase related to Field Services’ Sarbanes-Oxley compliance costs.
Other Income, Net of Expenses. The decrease was driven primarily by:
•
A $23 million decrease due to impairment charges in 2004 related to management’s assessment of the recoverability of certain equity method investments
•
A $13 million decrease due to the gains on sales of equity method investments in 2003, partially offset by
•
A $7 million increase in equity earnings primarily due to increased earnings from equity method investments.
Minority Interest Expense. Minority interest expense increased in 2004 compared to 2003 due to increased earnings from DEFS, Duke Capital’s joint venture with ConocoPhillips. The increase was not proportionate to the increase in Field Services’ earnings, as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Capital corporate level that are not included in DEFS’ results.
EBIT. The increase in EBIT in 2004 compared to 2003 resulted primarily from the favorable effects of commodity prices and improved results from trading and marketing activities, partially offset by NGL and raw natural gas sales volume declines and impairments. The full impact from the effects of commodity prices were not realized as some sales volumes were previously hedged at prices different than actual market prices at settlement.
Matters Impacting Future Field Services Results
Field Services has developed significant size and scope in natural gas gathering and processing and NGL marketing and plans to focus on operational excellence and organic growth. Field Services’ revenues and expenses are significantly dependent on prevailing commodity prices for NGLs and natural gas, and past and current trends in price changes of these commodities may not be indicative of future trends. Field Services anticipates that current price levels will continue to stimulate drilling and help to offset declining raw natural gas supplies. Although the prevailing price of natural gas has less short term significance to its operating results than the price of NGLs, in the long term, the growth and sustainability of Field Services’ business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production.
In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to cause a Duke Capital subsidiary to transfer a 19.7 % interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. In connection with this transaction, DEFS expects to transfer its Canadian assets to Duke Capital’s Natural Gas Transmission segment and receive certain U.S. Midstream assets or cash from ConocoPhillips. Upon completion of this transaction, DEFS will be owned 50 percent by Duke Capital and 50 percent by ConocoPhillips. As a result, Duke Capital
expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction. This transaction, which is subject to customary U.S. and Canadian regulatory approval, is expected to close in the latter half of 2005. This transaction is estimated to result in a pretax gain to Field Services of approximately $600 million. Additionally, in February 2005, DEFS sold its general partner in TEPPCO for approximately $1.1 billion and Duke Capital sold its limited partner interest in TEPPCO for approximately $100 million to Enterprise GP Holdings L.P., an unrelated third party. These transactions closed in the first quarter of 2005 and are estimated to result in a pretax gain to Field Services of approximately $900 million (net of approximately $330 million of minority interest).
As a result, Duke Capital expects to deconsolidate its investment in DEFS subsequent to the closing of the transfer of its 19.7% interest to ConocoPhillips. During the first quarter of 2005 Duke Capital has discontinued hedge accounting for certain 2005 and 2006 contracts held by Duke Capital related to Field Services’ commodity risk, which were previously accounted for as cash flow hedges. As a result of the discontinuation of hedge accounting treatment, approximately $140 million of pretax deferred losses in Accumulated Other Comprehensive Income (AOCI) related to these contracts have been charged against earnings by Duke Capital in the first quarter of 2005, which will impact Field Services’ segment EBIT. On a prospective basis, these contracts will be accounted for under the MTM Model, which will impact Other EBIT.
Future revenues, gas purchases and EBIT will continue to be sensitive to commodity prices that have historically been cyclical and volatile. Field Services equity NGL position for 2005 was approximately 64% hedged as of December 31, 2004 at an average crude price equivalent of $38 per barrel. After considering the impacts of hedging, Field Services exposure to a one cent per gallon change in the average price of NGLs is $5 million for 2005. This figure does not include the effects of discontinued hedge accounting for certain 2005 and 2006 contracts, previously accounted for as cash flow hedges. During the first quarter of 2005, these contracts began to be accounted for under the MTM Model and, as a result, Duke Capital’s earnings for 2005 and 2006 will be subject to more volatility.
Field services operating, and general and administrative costs are expected to increase in 2005, primarily due to asset integrity work and financial process improvements planned during the year. This increase is not expected to have a material effect on Field Services’ facility operating costs in 2005.
There are many important factors that could cause actual results to differ materially from the expectations expressed. Management can provide no assurances regarding the impact of future commodity prices or drilling activity.
Year Ended December 31, 2003 as Compared to December 31, 2002
Operating Revenues. The increase was driven primarily by:
•
A $2,200 million increase due primarily to a $2.17 per MMBtu increase in average natural gas prices
•
A $1,180 million increase due primarily to a $0.15 per gallon increase in average NGL prices, partially offset by
•
A $120 million decrease related to lower throughput of raw natural gas supply
•
A $395 million decrease related to lower NGL production, and
•
A $179 million decrease due to the impacts of cash flow hedging which reduced revenues by approximately $198 million for the year ended December 31, 2003 and by $19 million for the year ended December 31, 2002, as compared to what revenue would have been without any hedging.
Operating Expenses. The increase was primarily driven by:
•
A $2,920 million increase due to higher costs of raw natural gas and NGL supply
•
A $37 million increase related to other factors, including severance charges in 2003 and other employee related expenditures, partially offset by
•
A $455 million decrease due to lower throughput volumes, and
•
A $53 million decrease in 2003 operating expenses was due to 2002 charges related to Field Services internal review of balance sheet accounts ($37 million at Duke Capital’s 70% share), which may be related to corrections of accounting errors in periods prior to 2002. These adjustments were made in the following five categories: operating expense accruals; gas inventory valuations; gas imbalances; joint venture and investment account reconciliations; and other balance sheet accounts and were immaterial to Duke Capital’s reported results.
Minority Interest Expense. Minority interest expense at Field Services increased in 2003 compared to 2002 due to increased earnings from DEFS. The increase in minority interest expense was not proportionate to the increase in Field Services’ earnings as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Capital corporate level that are not included in DEFS results.
EBIT. EBIT for 2003 increased compared to 2002 as a result of better pricing and other factors discussed above.
DENA
(a)
Includes plant production from plants accounted for under the equity method
(b)
Excludes discontinued operations
Year Ended December 31, 2004 as Compared to December 31, 2003
Operating Revenues. The decrease was driven primarily by:
•
A $1,691 million decrease from lower natural gas sales volumes, due primarily to the continued wind down of DETM’s operations. This decrease was partially offset by approximately $73 million from higher average natural gas prices realized in the current year
•
A $309 million reduction in power generation revenues, due primarily to lower average power prices realized from hedging activities and lower volumes due primarily to the sale of the Southeast Plants
•
$25 million in lower net trading margins. In 2004, DENA recognized $25 million negative net trading margins.
Operating Expenses. The decrease was driven primarily by:
•
A $3,157 million decrease from 2003 impairments and other related charges, including $2,903 million of impairments, primarily related to DENA’s Southeast Plants and its partially completed
western plants, disqualification of certain hedges that were related to the impaired plants and goodwill impairment related to the trading and marketing business of $254 million
•
A $1,707 million decrease from lower natural gas purchase volumes, due primarily to the continued wind down of DETM’s operations. This decrease was partially offset by approximately $90 million from higher average natural gas prices realized in the current year
•
$184 million of lower general and administrative expense, primarily due to the impact of workforce reductions and associated office costs, travel and other benefits, reduced consulting costs and lower bad debt expense. A 2003 $28 million Commodity Futures Trading Commission (CFTC) settlement ($17 million net of minority interest expense) and 2003 severance costs of $10 million also contributed to a favorable variance in general and administrative expense
•
A $113 million ($108 million net of minority interest expense) decrease in operating expenses from a gain related to the settlement of the Enron bankruptcy proceedings in April 2004
•
$74 million of lower depreciation expense, primarily due to the sale of the Southeast Plants
•
A $27 million decrease in operations and maintenance expense, due primarily to the sale of the Southeast Plants and reduced costs from renegotiated outsourcing agreements, partially offset by two plants entering into commercial operation late in the second quarter of 2003
•
A $23 million reduction in plant fuel costs due primarily to lower volumes as a result of the sale of the Southeast Plants, partially offset by
•
A $105 million increase in operating expenses from a charge related to the California and Western U.S. energy markets settlement in June 2004 (see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies”).
Losses on Sales of Other Assets, net. Losses on sales of other assets for the year ended December 31, 2004 were due primarily to an approximate $360 million pre-tax loss associated with the sale of DENA’s Southeast Plants and approximately $65 million of pre-tax losses associated with the sales and terminations of DETM contracts. Partially offsetting these losses in 2004 were approximately $180 million of pre-tax gains associated with the sales of two DENA partially completed western plants (Luna and Moapa). (See Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions.”) Losses on sales of other assets for 2003 were $208 million due primarily to an $18 million pre-tax loss on the sale of the 25% net interest in the Vermillion facility, a $66 million pre-tax loss on the sale of turbines and $127 million of DETM pre-tax charges related to the sale of contracts.
Other Income, net of expenses. The decrease in other income, net of expenses was due primarily to the $178 million pre-tax gain in 2003 from the sale of DENA’s 50% interest in Ref-Fuel and the associated foregone equity earnings of $22 million.
Minority Interest Benefit. Minority interest benefit decreased due primarily to more favorable 2004 results at DETM as compared to 2003 as a result of the DETM wind-down of operations.
EBIT. EBIT increased primarily as a result of the decreased losses from impairments and other related charges, lower plant depreciation and operating expenses from the 2004 sale of the Southeast Plants and lower general and administrative expense. These increases were partially offset by reduced gross margin from lower net sales, net trading margins and values realized from hedge positions, in addition to increased losses on sales of assets, as outlined above.
Matters Impacting Future DENA Results
Duke Capital believes merchant energy will play a vital role in meeting the United States’ energy demand. A key objective for 2005 is to position DENA to be a successful merchant operator. During 2004, DENA’s business model changed to focus on selling fixed capacity contracts in addition to volume based sales and
purchases. Duke Capital is pursuing various options to create a sustainable business model for DENA, including consideration of potential business partners. A desirable business model would include fuel and geographic diversity, sufficient size and scope for a substantial market presence and would enable DENA to better withstand the cyclical nature of the industry. Depending on the option selected, there is a risk that material impairments could be recorded, including the potential disqualification of certain contracts and the recognition of unrealized loss associated with DENA power forward sales contracts designated under the normal purchases and normal sales exemption which totaled approximately $900 million as of December 31, 2004. This unrealized loss represents the difference in the normal purchases and normal sales contract prices compared to the forward market prices of power and is partially offset by unrealized gains on natural gas positions of approximately $800 million. (For more information see Commodity Price Risk discussion under Quantitative and Qualitative Disclosures about Market Risk.)
For 2005, DENA expects to significantly reduce its EBIT loss through additional cost savings, and higher gross margins. DENA’s marketing efforts in 2005 will focus on contracting capacity and energy production from its plants.
Year Ended December 31, 2003 as Compared to December 31, 2002
Operating Revenues. The increase was driven primarily by:
•
A $3,025 million increase related to the January 1, 2003 adoption of the final consensus on EITF Issue No. 02-03. See earlier discussion under “Consolidated Operating Revenues”
•
An increase in net trading margin driven by less unfavorable market changes in correlation and volatility in 2003 as compared to 2002, partially offset by a $76 million increase in 2002 from the appreciation of the fair value of the mark-to-market portfolio as a result of applying improved and standardized valuation modeling techniques to all North American regions, partially offset by
•
A $346 million reduction in overall power revenues, due primarily to $299 million decrease resulting from lower power prices and a $47 million decrease due to volumes delivered due to decreased demand.
Operating Expenses and Impairments. The increase was driven primarily by:
•
A $3,025 million increase due primarily to the adoption of the final consensus on EITF Issue No. 02-03, as described earlier
•
A $2,928 million increase due to asset impairments and other related charges related to current market conditions and strategic actions taken by management. For 2003 these charges totaled $3,157 million and related to $2,903 million of impairments, primarily on DENA’s Southeast Plants and its partially completed western plants, and disqualification of certain hedges that were related to the impaired assets; and goodwill impairment related to the trading and marketing business of $254 million. These amounts were offset by $229 million of charges taken in 2002 comprised of provisions for the termination of certain turbines on order and the write-down of other uninstalled turbines of $121 million, the write-off of site development costs (primarily in California) of $31 million, partial impairment of a merchant plant of $31 million, a charge of $24 million for the write-off of an information technology system and demobilization costs related to the deferral of three partially completed western plants of $22 million
•
A $32 million increase in overall gas costs due primarily to higher gas prices
•
A $62 million increase in other plant related operations, maintenance, and depreciation due primarily to increased costs associated with projects that entered into commercial operation during 2002 and 2003, and
•
A $117 million increase in other general and administrative expenses due primarily to a CFTC settlement in 2003 of $28 million ($17 million at Duke Capital’s 60% share) and the release of incentive accruals in 2002 of $89 million.
Losses on Sales of Other Assets, net. Losses on sales of other assets for 2003 were $208 million due primarily to an $18 million loss on the sale of the 25% net interest in the Vermillion facility, a $66 million loss on the sale of turbines and DETM charges related to the sale of contracts of $127 million.
Other Income, net of expenses. Other income, net of expenses increased in 2003, compared to 2002. The increase was driven primarily by:
•
A $178 million increase due to a gain on the sale of DENA’s 50% ownership interest in Ref-Fuel to Highstar Renewable Fuels LLC in 2003, partially offset by
•
A $33 million decrease due to 2002 settlements received on disputed items at two generating facilities and interest income related to a note receivable associated with the sale of an interest in a generating facility in 2002, and
•
Remaining decrease due primarily to lower equity earnings from Ref-Fuel.
Minority Interest Benefit. Minority interest benefit increased in 2003 compared to 2002, due to increased losses at DETM.
EBIT. EBIT for 2003 decreased compared to 2002. The decrease was due primarily to those factors discussed above: plant impairments, disqualification of certain hedges, the wind down of DETM, the write-off of goodwill, narrowed spark spreads, and increases in 2002 related to the appreciation of the fair value of the mark-to-market portfolio.
International Energy
(a)
Excludes discontinued operations
Year Ended December 31, 2004 as Compared to December 31, 2003
Operating Revenues. The increase was driven primarily by:
•
A $32 million increase due to the fourth quarter 2003 completion of the 160 MW Planta Arizona expansion in Guatemala
•
A $22 million increase in volumes due to higher electricity dispatch in Ecuador as a result of unplanned outages at competing generators
•
A $20 million increase in Brazil resulting from higher contracted sales prices of $26 million which were positively impacted by inflation adjustments primarily offset by the impact of a 2003 regulatory audit revenue adjustment
•
A $12 million increase due to higher electricity prices caused by low water availability in Peru
•
A $12 million increase due to favorable exchange rates primarily in Brazil, partially offset by
•
A $48 million decrease in Guatemala and El Salvador due to decreased cross border power marketing activity resulting from unfavorable market conditions, and
•
A $33 million decrease in natural gas sales due to the termination of a natural gas sales contract from the liquefied natural gas business in 2003.
Operating Expenses. The increase was driven primarily by:
•
A $23 million increase due to the fourth quarter 2003 completion of the 160 megawatt (MW) Planta Arizona expansion in Guatemala as discussed above
•
A $21 million increase in electricity generation costs resulting from higher levels of dispatch in Ecuador as described above
•
An $18 million increase due to a reserve reduction in 2003 related to the early termination of a natural gas sales contract from the liquefied natural gas business
•
A $17 million increase in Peru power purchases to satisfy sale contract requirements caused by decreased generation as a result of low water availability
•
A $14 million increase due to general and administrative expenses primarily due to higher corporate allocations and Sarbanes-Oxley compliance costs
•
A $12 million increase in Brazil due primarily to increased transmission fees and other costs offset by an environmental charge recorded in 2003 and a reduction in the environmental reserves in 2004, partially offset by
•
A $42 million decrease in spot market purchases in Guatemala and El Salvador due to decreased cross border power marketing activity
•
A $37 million decrease in natural gas sales purchases due to the termination of a natural gas sales contract from the LNG business in 2003 and
•
A $13 million charge associated with the disposition of the ownership share in the Compañia de Nitrógeno de Cantarell, S.A. de C.V. (Cantarell) nitrogen facility in Mexico.
Other Income, net of expenses. The increase was primarily the result of:
•
An $11 million increase due to a 2003 adjustment related to revenue recognition for the Cantarell equity investment, and
•
A $6 million increase due to favorable netback pricing at National Methanol Company
EBIT. EBIT increased modestly in 2004 compared to 2003. The slight increase was due to the factors described above.
Matters Impacting Future International Energy Results
International Energy’s current strategy is focused on selectively growing its Latin American power generation business while continuing to maximize the returns and cash flow from its current portfolio.
EBIT results for International Energy are sensitive to changes in hydrology, power supply, power demand and fuel prices. Regulatory matters can also impact EBIT results, as well as impacts from fluctuations in exchange rates, most notably the Brazilian Real.
During 2005, Duke Capital’s Brazilian affiliate may participate in the next regulated auction for the sale of power to the distribution companies. The auction process provides for 8 year contracts with delivery commencing in 2008 and 2009. The outcome of these auctions could impact International Energy’s EBIT results for the years 2008 and beyond.
International Energy owns a 50% joint venture interest in Compañía de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche). Campeche operates a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican national oil company (PEMEX). The current five year GCSA expires on October 31, 2006 and PEMEX has the option to renew the GCSA for an additional four years. Campeche has made a renewal offer to PEMEX that has been initially rejected; however, discussions continue with PEMEX regarding renewal of the contract or other possible arrangements. If it is determined that the renewal will not take place or another economically viable arrangement is not found, the value of International Energy’s equity investment in Campeche would decline and such investment would be written down to its resulting fair value. International Energy’s estimated maximum exposure to this risk is potential impairment or other charges of $70 million.
Certain of International Energy’s long-term sales contracts and long-term debt in Brazil contain inflation adjustment clauses. While this is favorable to revenue in the long run, as International Energy’s contract prices are adjusted, there is an unfavorable impact on interest expense resulting from revaluation of International Energy’s outstanding local currency debt. In general, interest rates were lower in 2004 than in 2003 and the resulting impact on contract revenues and interest expense in 2004 was not as great as in 2003.
Year Ended December 31, 2003 as Compared to December 31, 2002
Operating Revenues. The decrease was driven primarily by:
•
A $91 million nonrecurring favorable impact on 2002 revenues as a result of a Brazilian regulatory ruling in March 2002 that affected all Brazilian energy market participants and finalized the methodology to calculate revenues and expenses related to the 2001 electricity rationing, which is offset in operating expenses
•
A change in methodology in Peru to reflect a netting of the volumes transferred to/from the electricity grid in 2003 resulting in a $57 million revenue reduction, which is offset in expense
•
Lower revenues of $35 million in El Salvador as a result of a power sales contract not being renewed by a counterparty
•
Lower LNG sales of $33 million, due primarily to the termination of a gas sales contract
•
Unfavorable exchange rate impacts resulting in a decrease of $10 million in Brazil and Argentina, partially offset by
•
An increase of $35 million related primarily to favorable recontracting terms on electricity sales contracts in Brazil
•
An increase of $25 million as a result of the completion of the 160 MW expansion in Guatemala, and
•
Increases to revenues and receivables for adjustments of $11 million as a result of a regulatory audit in Brazil.
Operating Expenses. The decrease was driven primarily by:
•
A $91 million nonrecurring favorable impact on 2002 operating expenses as a result of a Brazilian regulatory ruling in March 2002 that affected all Brazilian energy market participants and finalized the methodology to calculate revenues and expenses related to the 2001 electricity rationing, which is offset in operating revenues
•
A $75 million write-down in 2002 for the cancellation of capital projects in Brazil and Bolivia
•
A change in methodology in Peru to reflect a netting of the volumes transferred to/from the electricity grid in 2003 resulting in a $57 million expense reduction, which is offset in revenue
•
A $26 million charge and reserve for environmental settlements in Brazil
•
Lower expenses in the LNG business due to a $40 million charge recorded in 2002 for estimated probable losses due to the early termination of a natural gas sales contract and $31 million in lower gas purchases
•
Lower expenses of $19 million in El Salvador as a result of reduced contract sales volumes
•
Cost savings of $17 million from lower International Energy corporate expenses, partially offset by
•
Higher operating expenses of $22 million due to the completion of the 160 MW expansion in Guatemala.
Other Income, net of expenses. The decrease was primarily the result of:
•
A $43 million decrease in equity investment income in Mexico due to a change in revenue recognition, increased repair costs, lower revenue due to downtime, and currency translation, partially offset by
•
An $11 million increase in equity investment income at National Methanol Company due to favorable product prices.
EBIT. The increase was due primarily to the absence of $75 million in charges for project cancellations that occurred in 2002, favorable contract terms on the renewal of the initial contracts in Brazil, and increased volumes in Central America due to the completion of expansion projects. Other principal drivers included net increases of $40 million from the LNG business, $17 million due to lower administrative expenses, and $11 million on the equity investment income for National Methanol Company, offset by changes in revenue recognition and operating results in Mexico, as noted above.
Crescent
Year Ended December 31, 2004 as Compared to December 31, 2003
Operating Revenues. The increase was driven primarily by a $160 million increase in residential developed lot sales, due to increased sales at the LandMar division in northeastern and central Florida, the Palmetto Bluff project in Bluffton, South Carolina, The Sanctuary project near Charlotte, North Carolina, the Lake James projects in northwestern North Carolina and the Lake Keowee projects in northwestern South Carolina.
Operating Expenses. The increase was driven primarily by a $101 million increase in the cost of residential developed lot sales, due to increased developed lot sales at the projects noted above, $50 million in impairments and other related charges (net of $12 million minority interest as discussed below) related to Twin
Creeks, Texas and Payson, Arizona residential development projects and a $26 million increase in corporate administrative expense as a result of increased incentive compensation tied to increased operating results. (See Note 11 to the Consolidated Financial Statements, “Impairments, Severance, and Other Related Charges” for further discussion of Crescent’s impairments.)
Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The increase was driven primarily by:
•
A $31 million increase in commercial project sales, resulting primarily from the sale of a commercial project in the Washington, D.C. area in March 2004
•
A $63 million increase in real estate land sales due primarily to the sale of the Alexandria and Arlington land tracts in the Washington, D.C. area in 2004, and
•
A $16 million increase in land management or “legacy” land sales, due to several large sales closed in the first quarter of 2004.
Minority Interest (Benefit) Expense. The increase in minority interest benefit is primarily due to $12 million of benefit related to impairment and bad debt charges at the Payson, Arizona project as noted above offset by an additional $8 million in minority interest expense related to increased earnings from the LandMar division.
EBIT. As discussed above, the increase in EBIT was driven primarily by an increase in residential developed lot sales and commercial project sales, the sale of the Washington, D.C. area land tracts and an increase in “legacy” land sales.
Matters Impacting Future Crescent Results
While Crescent regularly refreshes its property holdings, 2004 results reflected an opportunistic sale of property in the Washington, DC area which resulted in higher than normal gains during 2004. Crescent expects segment EBIT from continuing operations and discontinued operations to return to a more normal level of approximately $150 million in 2005. When property management or other significant accounting involvement is not retained by Crescent after the sale of an operating property, the transaction is recorded in discontinued operations.
Year Ended December 31, 2003 as Compared to December 31, 2002
Operating Revenues. The increase was driven primarily by increased revenues of $69 million from residential developed lot sales offset by a $5 million decrease in commercial rents. Residential developed lot sales increased in 2003 primarily due to sales at the Palmetto Bluff project in Bluffton, South Carolina of $51 million and increased sales in an existing project in Florida of $28 million. The decrease in commercial rents was due to a smaller portfolio of commercial properties in 2003 as a result of decreased development activities in the commercial sector.
Operating Expenses. The cost of residential developed lot sales increased $50 million as a result of increased sales as discussed above.
Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The decrease was due to a $40 million decrease in legacy land sales offset by a $17 million increase in commercial land sales. The decrease in legacy land sales was due to a declining inventory of large, contiguous tracts in North and South Carolina, as well as a decrease in demand by large tract purchasers. The increase in commercial land sales was due to the initial sales of land at our Potomac Yard project in the Washington, DC area.
EBIT. The decrease was primarily the result of decreased land management sales partially offset by increased earnings from commercial land sales and residential developed lot sales.
Other
Year Ended December 31, 2004 as Compared to December 31, 2003
Operating Revenues. Operating revenues for 2004 decreased $146 million, compared to 2003. The decrease was driven primarily by a $162 million decrease due to the sale of Energy Delivery Services (EDS) in December 2003.
Operating Expenses. The decrease was driven primarily by:
•
A $150 million decrease as a result of the sale of EDS in December 2003
•
A $59 million decrease in 2004 as a result of the correction of an accounting error in prior periods related to reserves at Bison attributable to property losses at several Duke Capital subsidiaries
•
A $51 million write-off in 2003 related to a corporate risk management information system that was abandoned, partially offset by
•
A $72 million increase due to higher captive insurance expenses.
EBIT. EBIT increased in 2004 compared to 2003. The increase in EBIT was primarily driven by the reversal of insurance reserves at Bison and other reductions in operating expense.
Matters Impacting Future Other Results
Other is expected to remain mostly comprised of certain unallocated corporate costs, DukeNet, D/FD, and Bison. D/FD will continue to decrease its earnings as the partnership winds down by the end of 2005.
Duke Capital expects to deconsolidate its investment in DEFS subsequent to the closing of the transfer of its 19.7% interest to ConocoPhillips. During the first quarter of 2005 Duke Capital has discontinued hedge accounting for certain 2005 and 2006 contracts held by Duke Capital related to Field Services’ commodity risk, which were previously accounted for as cash flow hedges. As a result of discontinuation of hedge accounting treatment, approximately $140 million of pretax deferred losses in AOCI related to these contracts have been reclassified into earnings by Duke Capital in the first quarter of 2005, which will impact Field Services’ segment EBIT. On a prospective basis, these contracts will be accounted for under the MTM Model, which will impact Other EBIT. As a result of these contracts being accounted for under the MTM Model, future earnings for Other in 2005 and 2006 will be subject to increased volatility.
Year Ended December 31, 2003 as Compared to December 31, 2002
Operating Revenues. The increase was driven primarily by:
•
A $70 million increase in revenues at EDS, as a result of EDS beginning operations in May 2002 and thus not recognizing a full year of operations in the prior year. EDS was sold in December 2003, partially offset by
•
A $172 million decrease due to the sale of Duke Engineering & Services, Inc. (DE&S) and DukeSolutions, Inc. (DukeSolutions) in 2002.
Operating Expenses. The decrease was primarily due to:
•
A $164 million decrease as a result of the sale of DE&S and DukeSolutions in 2002, partially offset by
•
A $72 million increase at EDS, as a result of EDS beginning operations in May 2002 and thus not recognizing a full year of operations in the prior year. EDS was sold in December 2003, and
•
A $51 million increase for a 2003 write-off related to a corporate risk management information system that was abandoned.
Other Income (Loss), net of expenses. Other income (loss), net of expenses increased in 2003, compared to 2002, due primarily to increased earnings related to D/FD.
EBIT. EBIT increased in 2003 compared to 2002. The increase in EBIT was primarily driven by the increase in other income, offset by decreases due to the sale of assets.
Other Impacts on Net (Loss) Income
Interest expense decreased $22 million in 2004 compared to 2003. The decrease was due primarily to:
•
A $112 million decrease from net debt reduction and refinancing activities, partially offset by
•
$33 million of lower capitalized interest due to decreased construction activity
•
$11 million of expenses related to financial instruments with characteristics of both liabilities and equity whose related distributions are now classified as interest expense instead of minority interest expense. Those instruments were classified as debt as of July 1, 2003, in accordance with SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity”
•
A $20 million increase associated with Canadian exchange rates, and
•
$17 million higher interest costs in Brazil, due to Duke Capital’s Brazilian debt being indexed annually to inflation and unfavorable impact of exchange rates.
Duke Capital’s projected interest expense is approximately $800 million for 2005. The projected reduction in interest expense from 2004 reflects the impact of Duke Capital’s net debt reductions in 2004.
Interest expense increased $209 million in 2003 as compared to 2002. The increase was due primarily to:
•
$136 million decrease in capitalized interest, resulting from lower plant construction activity in 2003, and
•
$32 million of expenses related to certain financial instruments with characteristics of both liabilities and equity whose related distributions were classified as interest expense in 2003 instead of minority interest expense.
Minority interest expense increased $156 million in 2004 as compared to 2003, and decreased $34 million in 2003 as compared to 2002. Through June 30, 2003, minority interest expense included expense related to regular distributions on trust preferred securities of Duke Capital. As of July 1, 2003, those distributions were accounted for as interest expense on a prospective basis in accordance with the adoption of SFAS No. 150. As a result of this accounting change, minority interest expense decreased $33 million for 2004 and $54 million for 2003.
Minority interest expense as shown and discussed in the preceding business segment EBIT sections includes only minority interest expense related to EBIT of Duke Capital’s joint ventures. It does not include minority interest expense related to interest and taxes of the joint ventures. Total minority interest expense related to the
joint ventures (including the portion related to interest and taxes) increased $189 million in 2004 as compared to 2003, and increased $20 million in 2003 as compared to 2002. The 2004 change was driven by increased earnings at Field Services and improved results at DENA as a result of the continued wind-down of DETM. The 2003 change was driven by increased earnings at DEFS and Natural Gas Transmission, offset by decreased earnings at DETM.
Income tax expense increased $2,098 million for the year ended December 31, 2004, compared to the same period in 2003, primarily due to the $3,211 million increase in earnings from continuing operations and $1,030 million of deferred tax expense recorded on restructuring of certain subsidiaries. The increases were partially offset by the $52 million reduction of state and federal income tax reserves and the pass-through of $86 million of income tax expense to Duke Energy. Income tax expense decreased $1,199 million in 2003, compared to 2002, due primarily to the large write-offs in 2003. (See Note 5 to the Consolidated Financial Statements, “Income Taxes,” for additional information.)
Income (loss) from discontinued operations was $259 million for 2004, ($166) million for 2003, and ($281) million for 2002. These amounts represent results of operations and gains (losses) on dispositions related primarily to International Energy’s Asia-Pacific Business and European Business, Duke Capital Partners, LLC (DCP), Field Services, DENA, and Crescent. (See Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale.”)
The 2004 amount is primarily comprised of a $273 million after-tax gain resulting from the sale of International Energy’s Asia-Pacific Business. The 2003 amount is primarily comprised of a $223 million after tax charge for International Energy’s impairment charges incurred as a result of classifying its Asia-Pacific assets as held for sale and exiting the European market. The 2002 amount is primarily comprised of $194 million charge for the impairment of goodwill for International Energy’s European Business.
During 2003, Duke Capital recorded a net-of-tax and minority interest cumulative effect adjustment for a change in accounting principles of $133 million as a reduction in earnings. The change in accounting principles included an after-tax and minority interest charge of $123 million related to the implementation of EITF Issue No. 02-03 and an after-tax charge of $10 million related to the implementation of SFAS No. 143, “Accounting for Asset Retirement Obligations.”
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The application of accounting policies and estimates is an important process that continues to evolve as Duke Capital’s operations change and accounting guidance evolves. Duke Capital has identified a number of critical accounting policies and estimates that require the use of significant estimates and judgments.
Management bases its estimates and judgments on historical experience and on other various assumptions that they believe are reasonable at the time of application. The estimates and judgments may change as time passes and more information about Duke Capital’s environment becomes available. If estimates and judgments are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. Duke Capital discusses its critical accounting policies and estimates and other significant accounting policies with senior members of management and the audit committee, as appropriate. Duke Capital’s critical accounting policies and estimates are listed below.
Risk Management Accounting
Duke Capital uses two comprehensive accounting models for its risk management activities in reporting its consolidated financial position and results of operations: the MTM Model and the Accrual Model. As further discussed in Note 1 to the Consolidated Financial Statements, the MTM Model is applied to trading and undesignated non-trading derivative contracts, the Accrual Model is applied to derivative contracts that are
accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, as well as to non-derivative contracts used for commodity risk management purposes. For the three years ended December 31, 2004, the determination as to which model was appropriate was primarily based on accounting guidance issued by the Financial Accounting Standards Board (FASB) and EITF. Effective January 1, 2003, Duke Capital adopted EITF Issue No. 02-03. While the implementation of such guidance changed the accounting model used for certain of Duke Capital’s transactions, especially non-derivative energy trading contracts, the overall application of the models remained the same.
Under the MTM Model, an asset or liability is recognized at fair value on the Consolidated Balance Sheets and the change in the fair value of that asset or liability is recognized in the Consolidated Statements of Operations during the current period. While DENA is the primary business segment that uses this accounting model, the International Energy and Field Services segments, as well as Other also have certain transactions subject to this model. For the years ended December 31, 2004 and 2003, Duke Capital applied the MTM Model to its derivative contracts, unless subject to hedge accounting or the normal purchase and normal sale exemption (as described below). For the year ended December 31, 2002, Duke Capital also applied the MTM Model to energy trading contracts, as defined by EITF Issue No 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”, which was superseded by EITF Issue No. 02-03.
The MTM Model is applied within the context of an overall valuation framework. All new and existing transactions are valued using approved valuation techniques and market data, and discounted using a London Interbank Offered Rate (LIBOR) based interest rate. When available, quoted market prices are used to measure a contract’s fair value. However, market quotations for certain energy contracts may not be available for illiquid periods or locations. If no active trading market exists for a commodity or for a contract’s duration, holders of these contracts must calculate fair value using internally developed valuation techniques or models. Key components used in these valuation techniques include price curves, volatility, correlation, interest rates and tenor. While volatility and correlation are the most subjective components, the price curve is generally the most significant component affecting the ultimate fair value for a contract subject to the MTM Model, especially after implementation of EITF Issue No. 02-03 due to the discontinuation of the MTM Model for certain energy trading contracts, such as transportation agreements. Prices for illiquid periods or locations are established by extrapolating prices for correlated products, locations or periods. These relationships are routinely re-evaluated based on available market data, and changes in price relationships are reflected in price curves prospectively. Consideration may also be given to the analysis of market fundamentals when developing illiquid prices. A deviation in any of the components affecting fair value may significantly affect overall fair value.
Valuation adjustments for performance and market risk, and administration costs are used to arrive at the fair value of the contract and the gain or loss ultimately recognized in the Consolidated Statements of Operations. While Duke Capital uses common industry practices to develop its valuation techniques, changes in Duke Capital’s pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. However, due to the nature and number of variables involved in estimating fair values, and the interrelationships among these variables, sensitivity analysis of the changes in any individual variable is not considered to be relevant or meaningful.
Validation of a contract’s calculated fair value is performed by an internal group independent of Duke Capital’s trading areas. This group performs pricing model validation, back testing and stress testing of valuation techniques, prices and other variables. Validation of a contract’s fair value may be done by comparison to actual market activity and negotiation of collateral requirements with third parties.
For certain derivative instruments, Duke Capital applies either hedge accounting or the normal purchase and normal sales exemption in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”. The use of hedge accounting and the normal purchase and normal sales exemption provide effectively for the use of the Accrual Model. Under this model, there is generally no recognition in the Consolidated Statements of Operations for changes in the fair value of a contract until the service is provided or the associated delivery period occurs (settlement).
Hedge accounting treatment is used when Duke Capital contracts to buy or sell a commodity such as natural gas at a fixed price for future delivery corresponding with anticipated physical sales or purchase of natural gas (cash flow hedge). In addition, hedge accounting treatment is used when Duke Capital holds firm commitments or asset positions and enters into transactions that “hedge” the risk that the price of a commodity, such as natural gas or electricity, may change between the contract’s inception and the physical delivery date of the commodity (fair value hedge). To the extent that the fair value of the hedge instrument offsets the transaction being hedged, there is no impact to the Consolidated Statements of Operations prior to settlement of the hedge. However, as not all of Duke Capital’s hedges relate to the exact location being hedged, a certain degree of hedge ineffectiveness may be recognized in the Consolidated Statements of Operations.
The normal purchases and normal sales exemption, as provided in SFAS No. 133 as amended and interpreted by Derivative Implementation Group (DIG) Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity,” and amended by SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” indicates that no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract (in Duke Capital’s case, the delivery of power). Previously, Duke Capital applied this exemption for certain contracts involving the sale of power in future periods. SFAS No. 149 includes certain modifications and changes to the applicability of the normal purchase and normal sales scope exception for contracts to deliver electricity. As a result, Duke Capital reevaluated its policy for accounting for forward power sale contracts and determined that substantially all forward contracts to sell power entered into after July 1, 2003 will be designated as cash flow hedges. To the extent that the hedge is perfectly effective, income statement recognition for the contract will be the same under either model.
In addition to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, the Accrual Model also encompasses non-derivative contracts used for commodity risk management purposes. For these non-derivative contracts, there is no recognition in the Consolidated Statements of Operations until the service is provided or delivery occurs.
For additional information regarding risk management activities, see Quantitative and Qualitative Disclosures about Market Risk. The Quantitative and Qualitative Disclosures about Market Risk include daily earnings at risk information related to commodity derivatives recorded using the MTM Model and an operating income sensitivity analysis related to hypothetical changes in certain commodity prices recorded using the Accrual Model.
Regulatory Accounting
Duke Capital accounts for certain of its regulated operations (primarily Natural Gas Transmission) under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, Duke Capital records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state, provincial and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income. Total regulatory assets were $953 million as of December 31, 2004 and $828 million as of December 31, 2003. Total regulatory liabilities were $124 million as of December 31, 2004 and $90 million as of December 31, 2003. (See Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”)
Long-Lived Asset Impairments and Assets Held For Sale
Duke Capital evaluates the carrying value of long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. For long-lived assets, an impairment would exist when the carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, the asset’s carrying value is adjusted to its estimated fair value. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used for developing estimates of future cash flows.
Duke Capital uses the best information available to estimate fair value of its long-lived assets and may use more than one source. Judgment is exercised to estimate the future cash flows, the useful lives of long-lived assets and to determine management’s intent to use the assets. The sum of undiscounted cash flows is primarily dependent on forecasted commodity prices for sales of power, natural gas or NGL, costs of fuel over periods of time consistent with the useful lives of the assets or changes in the real estate market. Management’s intent to use or dispose of assets is subject to re-evaluation and can change over time.
A change in Duke Capital’s plans regarding, or probability assessments of, holding or selling an asset could have a significant impact on the estimated future cash flows. Duke Capital considers various factors when determining if impairment tests are warranted, including but not limited to:
•
Significant adverse changes in legal factors or in the business climate;
•
A current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;
•
An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
•
Significant adverse changes in the extent or manner in which an asset is used or in its physical condition or a change in business strategy;
•
A significant change in the market value of an asset; and
•
A current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.
Judgment is also involved in determining the timing of meeting the criteria for classification as an asset held for sale under SFAS No. 144.
During 2004, Duke Capital recorded impairments on several of its long-lived assets. (For additional discussion of these impairments, see Note 11 to the Consolidated Financial Statements, “Impairment, Severance, and Other Related Charges.”)
Duke Capital may dispose of certain other assets in addition to the assets classified as “held for sale” at December 31, 2004. Accordingly, based in part on current market conditions in the merchant energy industry, it is reasonably possible that Duke Capital’s current estimate of fair value of its long-lived assets being considered for sale at December 31, 2004 and its other long-lived assets, could change and that change may impact the consolidated results of operations. In addition, Duke Capital could decide to dispose of additional assets in future periods, at prices that could be less than the book value of the assets.
Impairment of Goodwill
Duke Capital evaluates the impairment of goodwill under SFAS No. 142, “Goodwill and Other Intangible Assets”. The majority of Duke Capital’s goodwill at December 31, 2004 relates to the acquisition of Westcoast in
March 2002. The remainder relates to Field Services, International Energy’s Latin American operations and Crescent. As required by SFAS No. 142, Duke Capital performs an annual goodwill impairment test and updates the test if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Key assumptions used in the analysis include, but are not limited to, the use of an appropriate discount rate, estimated future cash flows and estimated run rates of general and administrative costs. In estimating cash flows, Duke Capital incorporates current market information as well as historical factors and fundamental analysis as well as other factors into its forecasted commodity prices. As a result of the 2004 impairment test required by SFAS No. 142, Duke Capital did not record any impairment on its goodwill. In the third quarter of 2003, Duke Capital recorded a $254 million goodwill impairment charge to write off all of DENA’s goodwill, most of which related to certain aspects of DENA’s trading and marketing business. This impairment charge reflected the reduction in scope and scale of DETM’s business and the continued deterioration of market conditions affecting DENA during 2003. In 2002, Duke Capital recorded a goodwill impairment charge of $194 million related to International Energy’s European Business, which was sold in 2003. Duke Capital used a discounted cash flow analysis utilizing the key assumptions described above to perform the analysis.
Management continues to remain alert for any indicators that the fair value of a reporting unit could be below book value and will assess goodwill for impairment as appropriate.
As of the acquisition date, Duke Capital allocates goodwill to a reporting unit. Duke Capital defines a reporting unit as an operating segment or one level below.
Revenue Recognition
Unbilled and Estimated Revenues. Revenues on sales of natural gas, natural gas transportation, storage and distribution as well as sales of petroleum products, primarily at Natural Gas Transmission and Field Services, are recognized when either the service is provided or the product is delivered. Revenues related to these services provided or products delivered but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information, estimated distribution usage based on historical data adjusted for heating degree days, commodity prices and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month.
Trading and Marketing Revenues. The recognition of income in the Consolidated Statements of Operations for derivative activity is primarily dependent on whether the Accrual Model or MTM Model is applied. Prior to January 1, 2003, Duke Capital applied the MTM Model to certain derivative contracts and certain contracts classified as energy trading pursuant to EITF Issue 98-10. With the implementation of EITF Issue 02-03, use of the MTM Model has been restricted to contracts classified as derivatives pursuant to SFAS No. 133. Contracts classified previously as energy trading that do not meet the definition of a derivative are subject to the Accrual Model. While the MTM Model is the default method of accounting for all SFAS No. 133 derivatives, SFAS No. 133 allows for the use of the Accrual Model for derivatives designated as hedges and certain scope exceptions, including the normal purchase and normal sale exception. Duke Capital designates a derivative as a hedge or a normal purchase or normal sale contract in accordance with internal hedge guidelines and the requirements provided by SFAS No. 133. (For further information regarding the Accrual or MTM Models, see Risk Management Accounting above. For further information regarding the presentation of gains and losses or revenue and expense in the Consolidated Statements of Operations, see Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies”.)
LIQUIDITY AND CAPITAL RESOURCES
Known Trends and Uncertainties
Duke Capital will rely primarily upon cash flows from operations, capital contributions from Duke Energy, and borrowings to fund its liquidity, capital and distribution requirements for 2005. Also, Duke Capital expects cash flows from asset sales and transfers related to Duke Capital transferring a 19.7% interest in DEFS to
ConocoPhillips as well as the sale by Field Services of TEPPCO and Duke Capital’s sale of its limited partner interests in TEPPCO Partners, L.P., as discussed below. The net cash from these transactions along with current cash, cash equivalents and short-term investment balances of approximately $1.6 billion, future cash generated from operations and capital contributions from Duke Energy may be periodically distributed to Duke Energy to facilitate Duke Energy repurchasing up to an aggregate of $2.5 billion of common stock over the next three years (See Subsequent Events). A material adverse change in operations or available financing may impact Duke Capital’s ability to fund its current liquidity and capital resource requirements. The relatively stable operating cash flows of the Natural Gas Transmission business currently composes a substantial portion of Duke Capital’s cash flow from operations and it is anticipated to continue to do so for the next several years.
Duke Capital currently anticipates net cash provided by operating activities in 2005 to be approximately $1 billion, including approximately $300 million of residential real estate capital expenditures. Net cash provided by operating activities in 2005 assumes a mid-year closing of the transfer of Duke Capital’s 19.7% interest in DEFS to ConocoPhillips, resulting in a change to equity method accounting treatment for Duke Capital’s remaining ownership interest in DEFS as any future cash distributions from DEFS to Duke Capital, subsequent to the closing of the transfer transaction, will be included in operating activities in the Consolidated Statements of Cash Flows. Achievement of these projected amounts is subject to a number of factors, including, but not limited to, regulatory constraints, economic trends, and market volatility.
Duke Capital projects 2005 capital and investment expenditures of approximately $1.5 billion, including approximately $300 million of residential real estate capital expenditures. Duke Capital continues to focus on reducing risk and restructuring its business for future success and will invest principally in its strongest business sectors with an overall focus on positive net cash generation. Based on this goal, approximately 50% of total projected 2005 capital expenditures are projected to be allocated to Natural Gas Transmission. Total projected capital and investment expenditures include approximately $400 million for maintenance and upgrades of existing pipelines and infrastructure. Additionally, Duke Capital anticipates approximately $470 million in capital and investment expenditures for Crescent, including $300 million of residential real estate capital expenditures. Expenditures at Crescent and Natural Gas Transmission constitute the majority of the expansion capital planned in 2005 by Duke Capital. Duke Capital is also focused on pursuing various options to create a sustainable business model at DENA, including consideration of potential business partners. See earlier discussion in Introduction section for more information.
In February 2005, DEFS sold its wholly-owned subsidiary TEPPCO for approximately $1.1 billion and Duke Capital sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to EPCO, an unrelated third party. These transactions closed in the first quarter of 2005 and are estimated to result in a pretax gain to Duke Capital of approximately $900 million (net of approximately $330 million of minority interest).
Additionally, in February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to cause a Duke Capital subsidiary to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. The consideration is expected to consist of the current Canadian operations of DEFS, the transfer of certain Canadian assets from ConocoPhillips to Duke Capital and the transfer of certain U.S. Midstream assets, or cash, from ConocoPhillips to DEFS, and the payment of cash from ConocoPhillips to Duke Capital of at least $500 million. Upon completion of this transaction, DEFS will be owned 50% by Duke Capital and 50% by ConocoPhillips. As a result, Duke Capital expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction. This transaction, which is subject to customary U.S. and Canadian regulatory approvals, is expected to close in the latter half of 2005.
As a result of the transactions discussed above, Duke Capital anticipates its debt to total capitalization ratio will remain below 50% at the end of 2005.
In 2005, Duke Capital expects to continue to reduce debt principally through the payment of contractual debt maturities and to begin to make periodic distributions to Duke Energy to facilitate a stock repurchase program. The amount of debt reduction and periodic distributions is subject to certain factors including the use of existing cash, cash equivalents and short-term investments of $1.6 billion at December 31, 2004, the receipt of cash proceeds from the TEPPCO sale and DEFS restructuring and other market-driven investment opportunities.
Duke Capital monitors compliance with all debt covenants and restrictions, and does not currently believe that it will be in violation or breach of its debt covenants. However, circumstances could arise that may alter that view. If and when management had a belief that such potential breach could exist, appropriate action would be taken to mitigate any such issue. Duke Capital also maintains an active dialogue with the credit rating agencies, and believes that the current credit ratings have stabilized. However, in February 2005, Moody’s Investor Service (Moody’s) changed the outlook for Duke Capital and DEFS to Negative, as a result of Duke Energy agreeing to cause a Duke Capital subsidiary to transfer a 19.7% interest in DEFS to ConocoPhillips, Field Services’ selling TEPPCO, Duke Capital selling its limited partner interests in TEPPCO Partners, L.P. and the $2.5 billion stock repurchase announcement by Duke Energy. In addition, Moody’s placed the credit ratings of Maritimes & Northeast Pipeline LLC and Maritimes & Northeast Pipeline LP under Review for Possible Downgrade in February 2005, due to concerns over downward revisions in gas reserve estimates for the Sable Offshore Energy Projects.
Operating Cash Flows
Net cash provided by operating activities was $2,333 million in 2004 compared to $1,801 million in 2003, an increase of $532 million. The increase in cash provided by operating activities was due primarily to higher cash settlements from trading and hedging activities, increased cash earnings related to Field Services, and increased cash flows in 2004 from changes in working capital related primarily to a cash refund received related to income taxes. Duke Capital made a $28 million voluntary contribution to its Westcoast retirement plans (Westcoast plans) in 2004. Duke Capital anticipates it will make $33 million in contributions to the Westcoast plans in 2005.
Net cash provided by operating activities was $1,801 million in 2003 compared to $3,173 million in 2002, a decrease of $1,372 million. The decrease in cash provided by operating activities was due primarily to lower cash settlements from trading and hedging activities and less cash flow in 2003 from changes in working capital, principally accounts payable and accounts receivable. Duke Capital made contributions to the Westcoast plans of approximately $11 million in 2003 and $9 million in 2002.
Investing Cash Flows
Cash provided by investing activities was $655 million in 2004 compared to $634 million in 2003, an increase of $21 million. Cash provided by investing activities was $634 million in 2003 compared to cash used of $5,772 million in 2002, a change of $6,406 million. The primary use of cash related to investing activities is capital and investment expenditures, detailed by business segment in the following table.
Capital and Investment Expenditures by Business Segment (a)
(a)
Amounts include the acquisition of Westcoast in 2002
(b)
Amounts include capital expenditures for residential real estate included in operating cash flows of $322 million in 2004, $196 million in 2003 and $179 million in 2002
(c)
Amounts include deferral of the consolidation of 50% of the profit earned by D/FD for the construction of DENA’s merchant generation plants, which is associated with Duke Capital’s share of ownership
Capital and investment expenditures, including Crescent’s residential real estate investments, decreased $200 million in 2004 compared to 2003. The decrease was due primarily to decreased investments in generating facilities at DENA due to the continuing downturn in the merchant energy portion of its business that began in 2002, and decreased investments at Gas Transmission due to the completion of infrastructure projects in western Canada and New England in 2003.
The increase in cash provided by investing activities in 2004 when compared to 2003 was impacted by a $292 million increase in proceeds from the sales of commercial and multi-family real estate at Crescent, due primarily to sales of the Potomac Yard retail center and the Alexandria land tract in 2004.
The increase in cash provided by investing activities in 2004 was also impacted by a $327 million decrease in net proceeds received from the sales of equity investments and other assets, primarily related to sales in 2003 of DENA’s 50% ownership interest in Ref-Fuel; Natural Gas Transmission’s sale of its wholly owned Empire State Pipeline and its investments in the Alliance Pipeline and Vector Pipeline, LP (Vector); Field Services’ sale of certain gathering pipelines and gas processing plants; Duke Capital’s sale of its TEPPCO Class B units and the monetization of various investments at DCP. These were partially offset by the sale of International Energy’s Asia-Pacific Business and DENA’s sale of its Southeast Plants and its Moapa and Luna partially completed facilities, and its Vermillion facilities, in 2004.
Capital and investment expenditures, including Crescent residential real estate investments, decreased $4,333 million in 2003 compared to 2002. The decrease was due primarily to the 2002 acquisition of Westcoast for $1,707 million, net of cash acquired, and lower investments in generating facilities at DENA, resulting from the downturn in the merchant energy portion of its business, the most significant of which were: a $621 million decrease due to 2002 expenditures on the Moapa, Grays Harbor, and Luna partially completed facilities; a $380 million decrease in expenditures for the Marshall, Sandersville, and Moss Landing facilities; and a $434 million decrease in turbine purchases. Capital and investment expenditures also decreased in 2003 due to a $268 million decrease in plant construction costs at International Energy, primarily in Australia; a $226 million decrease in investments in Natural Gas Transmission’s 50% interest in Gulfstream; and a reduction in Other investments, primarily related to DCP.
The decrease in cash used in investing activities in 2003 when compared to 2002 was also impacted by an increase in proceeds from the sale of equity investments and other assets, and sales of and collections on notes receivable of $1,466 million. The increased proceeds were primarily due to the sale of DENA’s 50% ownership interest in Ref-Fuel; Natural Gas Transmission’s sale of its wholly owned Empire State Pipeline, sale of its investment in the Alliance Pipeline and the associated Aux Sable liquids plant, Foothills Pipe Lines, Ltd, and Vector; Field Services’ sale of certain gathering pipelines and gas processing plants, Duke Capital’s sale of its TEPPCO Partners, L.P. Class B units; International Energy’s sale of its 85.7% majority interest in P.T. Puncakjaya Power and its European Business; and the monetization of various investments at DCP.
Financing Cash Flows and Liquidity
Duke Capital’s consolidated capital structure as of December 31, 2004, including short-term debt, was 47% debt, 47% member’s/common equity and 6% minority interests. As a result of Duke Capital transferring a 19.7% interest in DEFS to ConocoPhillips, Field Services selling TEPPCO, Duke Capital selling its limited partner interest in TEPPCO Partners, L.P. and Duke Capital’s planned periodic distributions to facilitate Duke Energy’s announced $2.5 billion stock repurchase program, Duke Capital anticipates its debt to total capitalization ratio
will remain below 50% at the end of 2005. The fixed charges coverage ratio, calculated using SEC guidelines, was 1.8 times for 2004 and 1.6 times for 2002. Earnings were inadequate to cover fixed charges by $2,384 million for the year ended December 31, 2003 as a result of approximately $3.5 billion in non-cash impairment charges incurred in 2003.
Net cash used in financing activities increased $561 million for the year ended December 31, 2004, compared to 2003. This change was due primarily to a decrease of approximately $1,050 million in capital infusions from Duke Energy, which were partially offset by $475 million of lower net paydowns of long-term debt, commercial paper and notes payable in 2004 as compared to 2003. Total net debt reductions of approximately $3.7 billion in 2004 consisted of approximately $3.0 billion in cash redemptions (see Note 14 to the Consolidated Financial Statements, “Debt and Credit Facilities”) and approximately $840 million of debt retired (as a non-cash financing activity) as part of the sale of International Energy’s Asia-Pacific Business, which were partially offset by minimal issuances of long-term debt. The $840 million does not include the approximately $50 million of Asia-Pacific debt which was placed in trust and fully funded in connection with the closing of the sale transaction and repaid in September 2004. The assets held in the consolidated trust were received from Alinta, Ltd. as part of the sale of the Asia-Pacific Business.
From 2002 to 2003 cash flows from financing activities decreased $5,016 million to net cash used in financing activities of $2,341 in 2003 from net cash provided by financing activities of $2,675 million in 2002. This change was due primarily to the net reduction of outstanding long-term debt, trust preferred securities, and notes payable and commercial paper during 2003 as compared to the same period in 2002 when Duke Capital acquired Westcoast and financed other business expansion projects. This change in cash flows from financing activities was aligned with Duke Capital’s strategy to reduce outstanding debt and strengthen the balance sheet. Additionally, capital infusions from Duke Energy were $575 million less in 2003 than in 2002.
During 2004, $267 million of cash was received by Duke Capital from Duke Energy as a partial return of the income tax benefit associated with the transfer of the deferred tax assets to Duke Energy (see Note 5 to the Consolidated Financial Statements, “Income Taxes”). The $267 million, which is comprised of $107 million that is presented as Advances from Parent in net cash used in financing activities and $160 million that is presented as changes from Taxes Accrued in net cash provided by operating activities in the 2004 Consolidated Statement of Cash Flows, was presented as an advance from parent in the December 31, 2004 Consolidated Balance Sheet, but converted to equity in early 2005 (see Note 10 to the Consolidated Financial Statements, “Investments in Unconsolidated Affiliates and Related Party Transactions”). During 2005, Duke Energy forgave these advances of $267 million. Also during 2005, Duke Capital anticipates receiving additional cash from Duke Energy to satisfy the residual balance of the transfer of the deferred tax assets.
Significant Financing Activities. In February 2004, Duke Capital remarketed $875 million of senior notes due in 2006, underlying Duke Energy’s 8.25% Equity Units and reset the interest rate from 5.87% to 4.302%. As this action was contemplated in the original Equity Units issuance, the transaction had no immediate accounting implications. Subsequently, Duke Capital exchanged $475 million of the remarketed senior notes for $200 million of 4.37% senior unsecured notes due in 2009 and $288 million of 5.5% senior unsecured notes due in 2014. In accordance with EITF Issue No. 96-19, “Debtors Accounting for a Modification or Exchange of Debt Instruments,” the $475 million of remarketed senior notes issued earlier at 4.302% was extinguished. This exchange transaction resulted in an approximate $11 million loss, which was included in Interest Expense in the Consolidated Statements of Operations for the year ended December 31, 2004. Proceeds from the remarketed notes were used to purchase U.S. Treasury securities that were held by the collateral agent and, upon maturity, were used to satisfy the forward stock purchase contract component of the Duke Energy 8.25% Equity Units in May 2004.
In April 2004, approximately $840 million of debt was retired (as a non-cash financing activity) as part of the sale of the Asia-Pacific operations. In September 2004, Duke Capital repaid approximately $50 million of Asia-Pacific debt from assets that were held in a consolidated trust for the specific purpose of retiring the debt. The assets held in the consolidated trust were received from Alinta, Ltd. as part of the sale of the Asia-Pacific Business. Duke Capital completed the sale of the Asia-Pacific assets, which includes substantially all of Duke Capital’s assets in Australia and New Zealand, to Alinta Ltd. on April 23, 2004.
In August 2004, Duke Capital redeemed the entire issue of its 8 3/8% debt due to an affiliate in 2029 for $250 million, in connection with the redemption of its Duke Capital Financing Trust III 8 3/8% Trust Preferred Securities. As the securities were redeemed at par, security holders received $25 per preferred security held, plus accrued and unpaid distributions to the redemption date.
Additionally, Duke Capital remarketed $750 million of its 4.32% senior notes due in 2006, underlying Duke Energy’s 8.00% Equity Units on August 11, 2004. As a result of the remarketing, the interest rate on the notes was reset to 4.331%, effective August 16, 2004. Duke Capital subsequently exchanged $400 million of the 4.331% notes for $408 million of 5.668% notes due in 2014. This transaction resulted in an approximate $6 million loss, which was included in Interest Expense in the Consolidated Statements of Operations for the year end December 31, 2004. Proceeds from the remarketed notes were used to purchase U.S. Treasury securities held by the collateral agent and, upon maturity, were used to satisfy the forward stock purchase contract component of the Duke Energy 8% Equity Units in November 2004.
In October 2004, Duke Capital prepaid a portion of a $994 million floating rate facility at DENA. The payment consisted of $565 million, an associated $35 million working capital facility and accrued interest on the facilities. Additionally, in December 2004, Duke Capital repaid the remaining outstanding balance of $429 million.
During 2004, Duke Capital purchased $202 million of its outstanding notes in the open market. These purchases included $140 million of Duke Capital 5.50% senior notes due March 1, 2014, $52 million of Duke Capital 4.37% senior notes due March 1, 2009, and $10 million of Duke Capital 6.75% senior notes due February 15, 2032. These securities were purchased at the then-current market price plus accrued interest.
Preferred and Preference Stock of Duke Capital’s Subsidiaries. In June 2004, Westcoast redeemed all remaining outstanding Cumulative Redeemable First Preferred Shares, Series 6. The Series 6 Shares were redeemed for 25.00 per share in Canadian dollars plus all accrued and unpaid dividends to the date of redemption for a total redemption amount of approximately 104 million Canadian dollars.
In October 2004, Westcoast redeemed all remaining outstanding Cumulative Redeemable First Preferred Shares, Series 9. The Series 9 Shares were redeemed for 25.00 per share in Canadian dollars plus all accrued and unpaid dividends to the date of redemption for a total redemption amount of 125 million Canadian dollars.
Available Credit Facilities and Restrictive Debt Covenants. As of December 31, 2004, credit facilities capacity was reduced by approximately $460 million compared to December 31, 2003, primarily related to the divested Asia-Pacific Business as discussed in Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale.” In addition, DEFS renewed and replaced its credit facility at a lower amount due to the reduced need for credit capacity. In October 2004, Duke Capital added two new credit facilities, including a $120 million bilateral credit facility with an expiration date of July 15, 2009 and a $130 million bilateral credit facility with an expiration date of October 18, 2007. Duke Capital intends to use both of these facilities for issuing letters of credit to support the business activities of its subsidiaries. The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the credit facilities.
Duke Capital’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2004, Duke Capital was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the credit agreements contain material adverse change clauses or any covenants based on credit ratings.
(For information on Duke Capital’s credit facilities as of December 31, 2004, see Note 14 to the Consolidated Financial Statements, “Debt and Credit Facilities.”)
Duke Capital has approximately $1,150 million of credit facilities which expire in 2005. It is Duke Capital’s intent to resyndicate the $1,150 million of expiring credit facilities.
Credit Ratings. The most recent change to the credit ratings of Duke Capital and its subsidiaries occurred in February 2004, when Standard and Poor’s (S&P) lowered its long-term ratings of Duke Capital and its subsidiaries (with the exception of Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively, M&N Pipeline) DEFS and DETM) one ratings level. S&P’s actions were based upon Duke Energy’s weaker than anticipated financial performance in 2003 and the execution risk associated with Duke Energy’s 2004 debt reduction plans. Additionally, S&P noted that Duke Energy’s continuation of trading and marketing activities around merchant generation will continue to expose Duke Energy to market risk and the need to dedicate material liquidity to support such activities. At the conclusion of S&P’s actions, Duke Capital and its subsidiaries were placed on Stable Outlook, with the exception of DETM, which was changed from Negative Outlook to Stable in July 2004. In addition, S&P changed the outlook of all of Duke Energy and its subsidiaries (with the exception of M&N Pipeline and DEFS) from Stable to Positive in December 2004 and then from Positive to Stable in February 2005. Also, in February 2005, Moody’s changed the outlook of Duke Capital and DEFS from Stable to Negative and placed the ratings of M&N Pipeline to under Review for Possible Downgrade. The following table summarizes the March 1, 2005 credit ratings from the agencies retained by Duke Capital to rate its securities, its principal funding subsidiaries and its trading and marketing subsidiary DETM.
Credit Ratings Summary as of March 1, 2005
a
Represents senior unsecured credit rating
b
Represents senior secured credit rating
c
Represents corporate credit rating
Duke Capital’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures while balancing the distributions to Duke Energy facilitating the stock repurchase program announced in February 2005 and maintaining the strength of its current balance sheet. If, as a result of market conditions or other factors, Duke Capital is unable to maintain its current balance sheet strength, or if its earnings and cash flow outlook materially deteriorates, Duke Capital’s credit ratings could be negatively impacted.
Duke Capital and its subsidiaries are required to post collateral under trading and marketing and other contracts. Typically, the amount of the collateral is dependent upon Duke Capital’s economic position at points in time during the life of a contract and the credit rating of the subsidiary (or its guarantor, if applicable) obligated under the collateral agreement. Business activity by DENA generates the majority of Duke Capital’s collateral requirements. DENA transacts business through DETM or Duke Energy Marketing America LLC, a wholly owned subsidiary of Duke Capital.
A reduction in DETM’s credit rating to below investment grade as of December 31, 2004 would have resulted in Duke Capital posting additional collateral of up to approximately $160 million. Additionally, in the
event of a reduction in DETM’s credit rating to below investment grade, collateral agreements may require the segregation of cash held as collateral to be placed in escrow. As of December 31, 2004, Duke Capital would have been required to escrow approximately $280 million of such cash collateral held if DETM’s credit rating had been reduced to below investment grade. Amounts above reflect Duke Capital’s 60% ownership of DETM and the allocation of collateral to DENA for contracts executed by DETM on its behalf.
A reduction in the credit rating of Duke Capital to below investment grade as of December 31, 2004 would have resulted in Duke Capital posting additional collateral of up to approximately $380 million. Additionally, in the event of a reduction in Duke Capital’s credit rating to below investment grade, certain interest rate and foreign exchange swap agreements may require settlement payments due to termination of the agreements. As of December 31, 2004, Duke Capital could have been required to pay up to $140 million in such settlement payments if Duke Capital’s credit rating had been reduced to below investment grade. Duke Capital would fund any additional collateral requirements through a combination of cash on hand and the use of credit facilities.
If credit ratings for Duke Capital or its affiliates fall below investment grade there is likely to be a negative impact on its working capital and terms of trade that is not possible to quantify fully in addition to the posting of additional collateral and segregation of cash described above.
Other Financing Matters. As of December 31, 2004, Duke Capital and its subsidiaries had effective SEC shelf registrations for up to $1,092 million in gross proceeds from debt and other securities. This represents an increase of approximately $92 million as compared to December 31, 2003, providing future funding flexibility. Of the total amount, $500 million represents available capacity at DEFS. On January 31, 2005 DEFS filed a Form 15 with the SEC to suspend its reporting obligations under the Securities and Exchange Act of 1934. Additionally, as of December 31, 2004, Duke Capital had access to 900 million Canadian dollars (U.S. $747 million) available under the Canadian shelf registrations for issuances in the Canadian market. A shelf registration is effective in Canada for a 25-month period. Of the total amount available under Canadian shelf registrations, 500 million Canadian dollars will expire in November 2005 and 400 million Canadian dollars will expire in July 2006.
While maintaining the financial strength of the consolidated company, Duke Energy has the ability to provide equity support to Duke Capital, as long as the source of the support excludes Duke Energy debt and trust preferred security funding. Duke Energy intends to provide such equity support as needed.
Distributions on Duke Capital’s limited liability company member interests will be paid when declared by the Board of Directors. Duke Capital did not pay distributions on its member’s/common equity in 2004, 2003, or 2002. Duke Capital continues to review its policy with respect to paying future distributions and anticipates making periodic distributions over the next three years to facilitate Duke Energy’s stock repurchase program announced in February 2005. (See Subsequent Events.)
Off-Balance Sheet Arrangements
Duke Capital and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. (See Note 17 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further details of the guarantee arrangements.)
Most of the guarantee arrangements entered into by Duke Capital enhance the credit standing of certain subsidiaries, non-consolidated entities or less than wholly-owned entities, enabling them to conduct business. As such, these guarantee arrangements involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Duke Capital having to honor its contingencies is largely dependent upon the future operations of the subsidiaries, investees and other third parties, or the occurrence of certain future events.
Issuance of these guarantee arrangements is not required for the majority of Duke Capital’s operations. Thus, if Duke Capital discontinued issuing these guarantee arrangements, there would not be a material impact to the consolidated results of operations, cash flows or financial position.
Duke Capital does not have any material off-balance sheet financing entities or structures, except for normal operating lease arrangements and guarantee arrangements. (For additional information on these commitments, see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies” and Note 17 to the Consolidated Financial Statements, “Guarantees and Indemnifications.”)
Contractual Obligations
Duke Capital enters into contracts that require payment of cash at certain specified periods, based on certain specified minimum quantities and prices. The following table summarizes Duke Capital’s contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as current liabilities on the Consolidated Balance Sheets, other than current maturities of long-term debt. It is expected that the majority of current liabilities on the Consolidated Balance Sheets will be paid in cash in 2005.
Contractual Obligations as of December 31,
(a)
See Note 14 to the Consolidated Financial Statements, “Debt and Credit Facilities”. Amount also includes interest payments over life of debt.
(b)
See Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies”.
(c)
Includes firm capacity payments that provide Duke Capital with uninterrupted firm access to natural gas transportation and storage, electricity transmission capacity, refining capacity and the option to convert natural gas to electricity at third-party owned facilities (tolling arrangements) in some natural gas and power locations throughout North America.
(d)
Includes contractual obligations to purchase physical quantities of electricity, natural gas and NGLs. Amount includes certain normal purchases, energy derivatives and hedges per SFAS No. 133. For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2004. For certain of these amounts, Duke Capital may settle on a net cash basis since Duke Capital has entered into payment netting agreements with counterparties that permit Duke Capital to offset receivables and payables with such counterparties. A significant portion of these amounts pertain to DENA’s physical purchase commitments of electricity. Since DENA primarily markets electricity, consideration should be given to DENA’s forward sales of electricity, which exceed their forward purchases, when assessing the potential implications of these physical purchase commitments.
(e)
Includes purchase commitments for outsourcing of certain real estate services, contracts for software and consulting or advisory services. Amount also includes contractual obligations for engineering, procurement and construction costs for pipeline and real estate projects, and major maintenance of certain merchant plants.
(f)
Includes expected retirement plan contributions for 2005 (see Note 19 to the Consolidated Financial Statements, “Employee Benefit Plans”) and asset retirement obligations expected to settle. Duke Capital has not determined these amounts beyond 2009. Amount excludes reserves for litigation, environmental remediation and self-insurance claims (see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies”) because Duke Capital is uncertain as to the timing of when cash payments will be
required. Additionally, amount excludes annual insurance premiums that are necessary to operate the business (see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies”) funding of other post-employment benefits (see Note 19 to the Consolidated Financial Statements, “Employee Benefit Plans”) and regulatory credits (see Note 4 to the Consolidated Financial Statements, “Regulatory Matters”) because the amount and timing of the cash payments are uncertain. Also amount excludes Deferred Income Taxes and Investment Tax Credits on the Consolidated Balance Sheets since cash payments for income taxes are determined based primarily on taxable income for each discrete fiscal year. Liabilities Associated with Assets Held for Sale (see Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”) are also excluded as Duke Capital expects these liabilities will be assumed by the buyer upon sale of the assets.
Quantitative and Qualitative Disclosures About Market Risk
Risk and Accounting Policies
Duke Capital is exposed to market risks associated with commodity prices, credit exposure, interest rates, equity prices and foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. Duke Capital’s President and Chief Financial Officer are responsible for the overall approval of market risk management policies and the delegation of approval and authorization levels. Duke Energy’s Executive Committee which is composed of senior executives, receives periodic updates from the Chief Risk Officer (CRO) and other members of management, on market risk positions, corporate exposures, credit exposures and overall risk management activities. The CRO is responsible for the overall governance of managing credit risk and commodity price risk, including monitoring exposure limits.
See Critical Accounting Policies-Risk Management Accounting and Revenue Recognition-Trading and Marketing Revenues for further discussion of the accounting for derivative contracts.
Commodity Price Risk
Duke Capital is exposed to the impact of market fluctuations in the prices of natural gas, electricity, NGLs and other energy-related products marketed and purchased as a result of its ownership of energy related assets, remaining proprietary trading contracts, and interests in structured contracts classified as undesignated. Duke Capital employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity derivatives, including forward contracts, futures, swaps and options. (See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies” and Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)
Validation of a contract’s fair value is performed by an internal group independent of Duke Capital’s trading areas. While Duke Capital uses common industry practices to develop its valuation techniques, changes in Duke Capital’s pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition.
Hedging Strategies. Duke Capital closely monitors the risks associated with these commodity price changes on its future operations and, where appropriate, uses various commodity instruments such as electricity, natural gas, crude oil and NGL forward contracts to mitigate the effect of such fluctuations on operations. Duke Capital’s primary use of energy commodity derivatives is to hedge the output and production of assets and other contractual positions it owns.
To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the Consolidated Statements of Operations until delivery or settlement occurs. Accordingly, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement. Several factors influence the effectiveness of a hedge contract, including counterparty credit risk and using contracts with different commodities or unmatched terms. Hedge effectiveness is monitored regularly and measured each month. (See Note 1 to the Consolidated Financial Statements, “Summary of Significant
Accounting Policies” and Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)
In addition to the hedge contracts described above and recorded on the Consolidated Balance Sheets, Duke Capital enters into other contracts that qualify for the normal purchases and sales exemption described in Paragraph 10 of SFAS No. 133 and DIG Issue No. C15. For contracts qualifying for the scope exception, no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract unless the contract is designated as the hedged item in a fair value hedge. Normal purchases and sales contracts are generally subject to collateral requirements under the same credit risk reduction guidelines used for other contracts. Duke Capital has applied this scope exception for certain contracts involving the purchase and sale of electricity at fixed prices in future periods. As discussed in Critical Accounting Policies and Estimates for risk management activities, Duke Capital determined that substantially all forward contracts to sell power entered into after July 1, 2003 will be designated as cash flow hedges. Income statement recognition for the contracts will be the same regardless of whether the contracts are accounted for as cash flow hedges or as normal purchases and sales, unless designated as the hedged item in a fair value hedge, assuming no hedge ineffectiveness. The unrealized loss associated with DENA power forward sales contracts designated under the normal purchases and normal sales exemption as of December 31, 2004 and 2003 was approximately $900 million and $700 million, respectively. This unrealized loss represents the difference in the normal purchases and normal sales contract prices compared to the forward market prices of power, and is partially offset by unrealized gains on natural gas positions of approximately $800 million and $400 million at December 31, 2004 and 2003, respectively, which are recorded on the Consolidated Balance Sheet in Unrealized Gains and Losses on Mark-to-Market and Hedging Transactions. However, a key objective for Duke Capital in 2005 is to position DENA to be a successful merchant operator. Duke Capital is pursuing various options to create a sustainable business model for DENA, including consideration of potential business partners. Depending on the option selected, there is a risk that material impairments or other losses could be recorded, including the potential disqualification of DENA’s power forward sales contracts designated under the normal purchases and normal sales exemption. This would result in the recognition of all unrealized losses associated with these forward contracts. (For more information, see discussion in Overview of Business Strategy in Introduction section of Management’s Discussion and Analysis).
Income recognition and realization related to normal purchases and normal sales contracts generally coincide with the physical delivery of power. However, Duke Capital’s decision to sell DENA’s Southeast Plants and reduce DENA’s interest in partially completed plants required the reassessment of all associated derivatives, including normal purchases and normal sales. This required a change from the application of the Accrual Model to the MTM Model for these contracts and resulted in recording substantial unrealized losses that had not previously been recognized in the Consolidated Financial Statements. Future decisions about Duke Capital’s ownership of assets may result in additional contracts related to commodity price risk being recognized in the Consolidated Financial Statements through a charge or credit to earnings.
Based on a sensitivity analysis as of December 31, 2004, it was estimated that a difference of one cent and ten cents per gallon in the average price of NGLs in 2005 would have a corresponding effect on operating income of approximately $5 million and $48 million, respectively (at Duke Capital’s 70% ownership in DEFS), after considering the effect of Duke Capital’s commodity hedge positions. Comparatively, the same sensitivity analysis as of December 31, 2003 estimated that operating income would have changed by approximately $6 million and $62 million for a one cent and ten cents per gallon difference in the average price of NGLs in 2004, respectively. These hypothetical calculations consider existing hedge positions and estimated production levels, but do not consider other potential effects that might result from such changes in commodity prices.
As a result of the high probability of Duke Capital deconsolidating its investment in DEFS, during the first quarter of 2005 Duke Capital has discontinued hedge accounting for certain 2005 and 2006 contracts held by Duke Capital related to Field Services’ commodity risk, which were previously accounted for as cash flow hedges. As a result, approximately $140 million of pretax deferred losses in AOCI related to these contracts have
been reclassified into earnings by Duke Capital in the first quarter of 2005. On a prospective basis, these contracts will be accounted for under the MTM Model and Duke Capital’s future earnings for 2005 and 2006 will be subject to more volatility.
Trading and Undesignated Contracts. The risk in the MTM portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily Earnings at Risk (DER) as described below. DER is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor risk in the trading portfolio on monthly and annual bases. These measures include limits on the nominal size of positions and periodic loss limits.
DER computations are based on historical simulation, which uses price movements over an eleven day period. The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for natural gas, electricity and other energy-related products. DER computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation. Duke Capital’s DER amounts for commodity derivatives recorded using the MTM Model are shown in the following table.
Daily Earnings at Risk
(a)
DER measures the MTM portfolio’s impact on earnings. While this calculation includes both trading and undesignated contracts, the trading portion, as defined by EITF Issue No. 02-03, is not material.
(b)
This occurred on January 16, 2004.
DER is an estimate based on historical price volatility. Actual volatility can exceed assumed results. DER also assumes a normal distribution of price changes; thus, if the actual distribution is not normal, the DER may understate or overstate actual results. DER is used to estimate the risk of the entire portfolio, and for locations that do not have daily trading activity, it may not accurately estimate risk due to limited price information. Stress tests are employed in addition to DER to measure risk where market data information is limited. In the current DER methodology, options are modeled in a manner equivalent to forward contracts which may understate the risk. The increase in estimated average DER for 2004 versus 2003 is primarily attributable to the DENA disqualified hedges included in the DER calculation for the full year in 2004 and only a portion of 2003 due to the timing of associated plant impairments and deferrals which resulted in the hedge disqualification.
During the first quarter of 2005, Duke Capital discontinued hedge accounting for certain contracts held by Duke Capital related to Field Services’ commodity risk. Since these contracts will be accounted for under the MTM Model prospectively, Duke Capital’s 2005 DER figures will be higher than the period ending 2004 DER and may, on average, be higher than the estimated average 2004 DER.
Duke Capital’s exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms. The following table illustrates the movement in the fair value of Duke Capital’s trading instruments during 2004.
Changes in Fair Value of Duke Capital’s Trading Contracts During 2004
Fair Value of Duke Capital’s Trading Contracts as of December 31, 2004
The “prices supported by quoted market prices and other external sources” category includes Duke Capital’s New York Mercantile Exchange (NYMEX) futures positions in natural gas, crude oil, propane, heating oil, and unleaded gasoline. The NYMEX has quoted monthly natural gas prices for the next 72 months and quoted monthly crude oil prices for the next 30 months. The NYMEX has quoted monthly prices for varying periods of 18 months or less for propane, heating oil, and unleaded gasoline. In addition, this category includes Duke Capital’s forward positions and options in natural gas, natural gas basis swaps, and power at points for which over-the-counter (OTC) broker quotes are available. On average, OTC quotes for power and natural gas forwards and swaps extend 48 months into the future. OTC quotes for natural gas options extend 12 months into the future, on average. Duke Capital values these positions using internally developed forward market price curves that are validated and recalibrated against OTC broker quotes. This category also includes “strip” transactions whose prices are obtained from external sources and then modeled to daily or monthly prices as appropriate.
The “prices based on models and other valuation methods” category includes (i) the value of options not quoted by an exchange or OTC broker, (ii) the value of transactions for which an internally developed price curve was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point, and (iii) the value of structured transactions. In certain instances structured transactions can be decomposed and modeled by Duke Capital as simple forwards and options based on actively quoted prices. Although the valuation of the individual simple structures may be based on quoted market prices, the effective model price for any given period is a combination of prices from two or more different instruments and such transactions therefore are included in this category due to its complex nature. As a result of the adoption of EITF Issue No. 02-03 in January 2003, all of the contracts in the “prices based on models and other valuation methods” category as of December 31, 2004 are derivatives as defined by SFAS No. 133.
Credit Risk
Credit risk represents the loss that Duke Capital would incur if a counterparty fails to perform under its contractual obligations. To reduce credit exposure, Duke Capital seeks to enter into netting agreements with
counterparties that permit Duke Capital to offset receivables and payables with such counterparties. Duke Capital attempts to further reduce credit risk with certain counterparties by entering into agreements that enable Duke Capital to obtain collateral or to terminate or reset the terms of transactions after specified time periods or upon the occurrence of credit-related events. Duke Capital may, at times, use credit derivatives or other structures and techniques to provide for third-party credit enhancement of Duke Capital’s counterparties’ obligations.
Duke Capital’s principal customers for power and natural gas marketing and transportation services are industrial end-users, marketers, local distribution companies and utilities located throughout the U.S., Canada and Latin America. Duke Capital has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers and marketers throughout these regions. These concentrations of customers may affect Duke Capital’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, Duke Capital analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis.
The following table represents Duke Capital’s distribution of unsecured credit exposure with the largest 30 enterprise credit exposures at December 31, 2004. These credit exposures are aggregated by ultimate parent company, include on and off balance sheet exposures, are presented net of collateral, and take into account contractual netting rights.
Distribution of Largest 30 Enterprise Credit Exposures As of December 31, 2004
“Externally Rated” represents enterprise relationships that have published ratings from at least one major credit rating agency. “Internally Rated” represents those relationships which have no rating by a major credit rating agency. For those relationships, Duke Capital utilizes appropriate risk rating methodologies and credit scoring models to develop an internal risk rating which is intended to map to an external rating equivalent. The total of the unsecured credit exposure included in the table above represents approximately 38% of the gross fair value of Duke Capital’s Receivables and Unrealized Gains on Mark-to-Market and Hedging Transactions on the Consolidated Balance Sheet at December 31, 2004.
Duke Capital had no net exposure to any one customer that represented greater than 10% of the gross fair value of trade accounts receivable and unrealized gains on mark-to-market and hedging transactions at December 31, 2004. Based on Duke Capital’s policies for managing credit risk, its exposures and its credit and other reserves, Duke Capital does not anticipate a materially adverse effect on its financial position or results of operations as a result of non-performance by any counterparty.
Duke Capital’s industry has historically operated under negotiated credit lines for physical delivery contracts. Duke Capital frequently uses master collateral agreements to mitigate certain credit exposures, primarily in its marketing and trading operations. The collateral agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of an established threshold. The threshold amount represents an unsecured credit limit, determined in accordance with the corporate credit policy. The collateral agreement also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions.
Duke Capital also obtains cash or letters of credit from customers to provide credit support outside of collateral agreements, where appropriate, based on its financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.
Collateral amounts held or posted may be fixed or may vary depending on the terms of the collateral agreement and the nature of the underlying exposure and cover trading, normal purchases and normal sales, and hedging contracts outstanding. Duke Capital may be required to return certain held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. In many cases, Duke Capital’s and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted. If Duke Capital or its affiliates have a credit rating downgrade, it could result in reductions in Duke Capital’s unsecured thresholds granted by counterparties. Likewise, downgrades in credit ratings of counterparties could require counterparties to post additional collateral to Duke Capital and its affiliates. (See Liquidity and Capital Resources-Financing Cash Flows and Liquidity for additional discussion of downgrades.)
The change in market value of New York Mercantile Exchange-traded futures and options contracts requires daily cash settlement in margin accounts with brokers.
Interest Rate Risk
Duke Capital is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt and commercial paper. Duke Capital manages its interest rate exposure by limiting its variable-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. Duke Capital also enters into financial derivative instruments, including, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. (See Notes 1, 7 and 14 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments,” and “Debt and Credit Facilities.”)
Based on a sensitivity analysis as of December 31, 2004, it was estimated that if market interest rates average 1% higher (lower) in 2005 than in 2004, interest expense, net of offsetting impacts in interest income, would decrease (increase) by approximately $4 million. Comparatively, based on a sensitivity analysis as of December 31, 2003, had interest rates averaged 1% higher (lower) in 2004 than in 2003, it was estimated that interest expense, net of offsetting impacts in interest income, would have increased (decreased) by approximately $21 million. These amounts were estimated by considering the impact of the hypothetical interest rates on variable-rate securities outstanding, adjusted for interest rate hedges, short-term investments, cash and cash equivalents outstanding as of December 31, 2004 and 2003. The decrease in interest rate sensitivity was primarily due to a decrease in subsidiary debt and a decrease in outstanding variable-rate commercial paper, net of invested cash. If interest rates changed significantly, management would likely take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in Duke Capital’s financial structure.
Equity Price Risk
Bison, Duke Capital’s wholly-owned captive insurance subsidiary, maintains investments to fund various business risks and losses, such as workers compensation, property, business interruption and general liability. Those investments are exposed to price fluctuations in equity markets and changes in interest rates.
Duke Capital participates in Duke Energy Corporation’s non-contributory defined benefit retirement and postretirement benefit plans. The costs of providing such plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rate, the rate of increase in health care costs and contributions made to the plans. The market value of Duke Energy’s defined benefit retirement plan assets has been affected by
changes in the equity market since 2000. As a result, at September 30, 2004 (Duke Energy’s measurement date), Duke Energy’s pension plan obligation, excluding Westcoast, exceeded the value of the plan assets by $130 million and Duke Energy was therefore required to reduce the minimum pension liability as prescribed by SFAS No. 87 and SFAS No. 132, “Employers’ Disclosures about Pensions and Postretirement Benefits.”
Foreign Currency Risk
Duke Capital is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be hedged through debt denominated or issued in the foreign currency. Duke Capital may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. To monitor its currency exchange rate risks, Duke Capital uses sensitivity analysis, which measures the impact of devaluation of the foreign currencies to which it has exposure.
As of December 31, 2004, Duke Capital’s primary foreign currency rate exposures were the Canadian Dollar and the Brazilian Real. A 10% devaluation in the currency exchange rate in all of Duke Capital’s exposure currencies would result in an estimated net loss on the translation of local currency earnings of approximately $25 million to Duke Capital’s Consolidated Statements of Operations. The Consolidated Balance Sheets would be negatively impacted by approximately $450 million currency translation through the cumulative translation adjustment in AOCI.
OTHER ISSUES
Global Climate Change. The United Nations-sponsored Kyoto Protocol, which prescribes specific greenhouse gas emission-reduction targets for developed countries, became effective February 16, 2005. Of the countries where Duke Capital has assets, Canada is presently the only one that has a greenhouse gas reduction obligation under the Kyoto Protocol. That obligation is to reduce average greenhouse gas emissions to 6 percent below their 1990 level over the period 2008 to 2012. In anticipation of the Kyoto Protocol’s entry into force, the Canadian government has been developing an implementation plan that includes, among other things, an emissions intensity-based greenhouse gas cap-and-trade program for large final emitters (LFE). If an LFE program is ultimately enacted, then all of Duke Capital’s Canadian operations would likely be subject to the program beginning in 2008, with compliance options ranging from the purchase of CO2 emission credits to actual emission reductions at the source, or a combination of strategies.
In 2001, President George W. Bush declared that the United States would not ratify the Kyoto Protocol. Instead, the U.S. greenhouse gas policy currently favors voluntary actions, continued research, and technology development over near-term mandatory greenhouse gas reduction requirements. Although several bills have been introduced in Congress that would compel CO2 emission reductions, none have advanced through the legislature and presently there are no federal mandatory greenhouse gas reduction requirements. The likelihood of a federally mandated CO2 emissions reduction program being enacted in the near future, or the specific requirements of any such regime, is highly uncertain. Some states are contemplating or have taken steps to manage greenhouse gas emissions, and while a number of U.S. states in the Northeast and far West are discussing the possibility of implementing regional programs in the future, the outcome of such discussions is very uncertain.
Due to the uncertainty of the Canadian policy and the speculative nature of any U.S. federal and state policies, Duke Capital cannot estimate the potential effect of the Canadian greenhouse gas reduction policy currently under development, or the potential effect of U.S. greenhouse gas policy on future consolidated results of operations, cash flows or financial position. Duke Capital will continue to assess and respond to the potential implications of greenhouse gas policies applicable to its business operations in the United States and Canada.
(For additional information on other issues related to Duke Capital, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies.”)
New Accounting Standards
The following new accounting standards were issued, but have not yet been adopted by Duke Capital as of December 31, 2004:
SFAS No. 123 (Revised 2004), “Share-Based Payment”. In December of 2004, the FASB issued SFAS No. 123R, which replaces SFAS No. 123 and supercedes Accounting Principles Board (APB) Opinion 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim or annual period after June 15, 2005. The pro forma disclosures previously permitted under SFAS 123 no longer will be an alternative to financial statement recognition. Under SFAS 123R, Duke Energy must determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost and the transition method to be used at the date of adoption. The transition methods include prospective and retroactive adoption options. Under the retroactive option, prior periods may be restated either as of the beginning of the year of adoption or for all periods presented. The prospective method requires that compensation expense be recorded for all unvested awards at the beginning of the first quarter of adoption of SFAS 123R, while the retroactive methods would record compensation expense for all unvested awards beginning in the first period restated.
Duke Energy continues to assess the transition provisions and has not yet determined the transition method to be used nor has Duke Energy determined if any changes will be made to the valuation method used for share-based compensation awards issued to employees in future periods. The impact to Duke Capital in periods subsequent to adopting SFAS 123R will be dependent upon the nature of any equity-based compensation awards issued to employees, but Duke Capital does not anticipate the adoption of SFAS 123R on July 1, 2005 to have any material impact on its consolidated results of operations, cash flows or financial position.
SFAS No. 153, “Exchanges of Nonmonetary Assets-an amendment of APB Opinion No. 29”. In December of 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS No. 153 also eliminates APB Opinion 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS No. 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. The impact to Duke Capital of SFAS No. 153 will depend on the nature and extent of any exchanges of nonmonetary assets after the effective date, but Duke Capital does not currently expect SFAS No. 153 to have a material impact on its consolidated results of operations, cash flows or financial position.
EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations”. In November of 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS No. 144 have been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS No. 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus in EITF Issue No. 03-13 clarifies that the cash flows of
the eliminated component are not considered to be eliminated if the continuing cash flows represent “direct” cash flows, as defined in the consensus. The consensus also requires that the assessment of whether significant continuing involvement exists be made from the perspective of the disposed component. The assessment should consider whether (a) the continuing entity retains an interest in the disposed component sufficient to enable it to exert significant influence over the disposed component’s operating and financial policies or (b) the entity and the disposed component are parties to a contract or agreement that gives rise to significant continuing involvement by the ongoing entity. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified as held for sale in fiscal periods beginning after December 15, 2004. The impact to Duke Capital of EITF Issue No. 03-13 will depend on the nature and extent of any long-lived assets disposed of or held for sale after the effective date, but Duke Capital does not currently expect EITF Issue No. 03-13 to have a material impact on its consolidated results of operations, cash flows or financial position.
Subsequent Events
In February 2005, DEFS sold its wholly-owned subsidiary TEPPCO for approximately $1.1 billion and Duke Capital sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to EPCO, an unrelated third party.
Additionally, in February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to cause a Duke Capital subsidiary to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. The consideration is expected to consist of the current Canadian operations of DEFS, the transfer of certain Canadian assets from ConocoPhillips to Duke Capital and the transfer of certain U.S. Midstream assets, or cash, from ConocoPhillips to DEFS, and the payment of cash from ConocoPhillips to Duke Capital of at least $500 million. Upon completion of this transaction, DEFS will be owned 50% by Duke Capital and 50% by ConocoPhillips. As a result, Duke Capital expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction. This transaction, which is subject to customary U.S. and Canadian regulatory approvals, is expected to close in the latter half of 2005.
As a result, Duke Capital expects to deconsolidate its investment in DEFS, subsequent to the closing of the transfer of its 19.7% interest to ConocoPhillips. During the first quarter of 2005 Duke Capital has discontinued hedge accounting for certain 2005 and 2006 contracts held by Duke Capital related to Field Services’ commodity risk, which were previously accounted for as cash flow hedges. As a result of discontinuation of hedge accounting treatment, approximately $140 million of pretax deferred losses in AOCI related to these contracts have been reclassified into earnings by Duke Capital in the first quarter of 2005. On a prospective basis, these contracts will be accounted for under the MTM Model.
On March 1, 2005, notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. The bondholders were notified that these securities would be called on April 15, 2005, the earliest date at which these bonds can be redeemed.
On March 23, 2005, Duke Capital distributed $750 million to its parent, Duke Energy, to provide funding for the execution of Duke Energy’s accelerated share acquisition plan. The distribution was principally obtained from Duke Capital’s portion of the cash proceeds realized from the recent sale by DEFS of the general partner of TEPPCO Partners, L.P. and Duke Capital’s sale of its limited partner interests in TEPPCO Partners, L.P.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
See “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk.”
Item 8.
Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Member of Duke Capital LLC:
We have audited the accompanying consolidated balance sheets of Duke Capital LLC and subsidiaries (Duke Capital) (formerly known as Duke Capital Corporation) as of December 31, 2004 and 2003, and the related consolidated statements of operations, member’s/common stockholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of Duke Capital’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Duke Capital is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Duke Capital’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Duke Capital and subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 1, Duke Capital adopted the provisions of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” as of January 1, 2002. As discussed in Note 1 and Note 6, Duke Capital adopted the provisions of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” as of January 1, 2003. As discussed in Note 1, Duke Capital adopted the provisions of Statement of Financial Accounting Standards No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” as of July 1, 2003. As discussed in Note 1, Note 14, and Note 15, Duke Capital adopted the provisions of Statement of Financial Accounting Standards No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” as of July 1, 2003. As discussed in Note 1, Duke Capital adopted the provisions of Emerging Issues Task Force No. 02-03, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as of January 1, 2003.
As discussed in Note 5, Duke Capital realigned certain subsidiaries which resulted in Duke Capital recognizing federal and state tax expense of approximately $1,030 million for the year ended December 31, 2004 to eliminate deferred tax assets at the time of the reorganization.
As discussed in Note 21, Duke Capital agreed in February 2005 to sell its interests in TEPPCO to Enterprise GP Holdings L.P. and to transfer a 19.7% interest in Duke Energy Field Services to ConocoPhillips.
DELOITTE & TOUCHE LLP
Charlotte, North Carolina
March 30,
DUKE CAPITAL LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions)
See Notes to Consolidated Financial Statements.
DUKE CAPITAL LLC
CONSOLIDATED BALANCE SHEETS
(In millions)
See Notes to Consolidated Financial Statements
DUKE CAPITAL LLC
CONSOLIDATED BALANCE SHEETS
(In millions)
See Notes to Consolidated Financial Statements
DUKE CAPITAL LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
See Notes to Consolidated Financial Statements
DUKE CAPITAL LLC
CONSOLIDATED STATEMENTS OF MEMBER’S/COMMON STOCKHOLDER’S EQUITY AND COMPREHENSIVE INCOME (LOSS)
(In millions)
(a)
Foreign currency translation adjustments, net of $114 tax benefit in 2003.
(b)
Net unrealized gains on cash flow hedges, net of $180 tax expense in 2004, $56 tax expense in 2003 and $79 tax expense in 2002.
(c)
Reclassification into earnings from cash flow hedges, net of $48 tax benefit in 2004, $133 tax benefit in 2003, and $91 tax benefit in 2002.
(d)
Minimum pension liability adjustment, net of $2 tax expense in 2004, $6 tax benefit in 2003, and $8 tax benefit in 2002.
(e)
See Note 1 to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements
1. Summary of Significant Accounting Policies
Nature of Operations and Basis of Consolidation. Duke Capital LLC (collectively with its subsidiaries, Duke Capital), a wholly-owned subsidiary of Duke Energy Corporation (Duke Energy) is a leading energy company located in the Americas with a real estate subsidiary. On March 1, 2004, Duke Capital changed its form of organization from a corporation to a Delaware limited liability company by effecting a conversion pursuant to Section 266 of the General Corporation Law of the State of Delaware and Section 18-214 of the Delaware Limited Liability Company Act. Pursuant to the conversion, all rights and liabilities of Duke Capital Corporation in its previous corporate form vested in Duke Capital as a limited liability company. As a result, the Consolidated Balance Sheet for 2004 no longer reflects Paid-in Capital and Retained Earnings as those accounts are now characterized as Member’s Equity. Duke Capital owns corporations who file as part of the Duke Energy consolidated federal income tax return and file their own respective foreign and state corporate income tax returns. The income tax expense related to these corporations is included in the income tax expense of Duke Capital.
Use of Estimates. To conform with generally accepted accounting principles (GAAP) in the United States, management makes estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge at the time, actual results could differ.
Reclassifications. Certain prior period amounts have been reclassified to conform to current year presentation. Such reclassifications include the reclassification of income from continuing operations to discontinued operations for certain operations (see Note 12).
The accompanying Consolidated Balance Sheet as of December 31, 2003 reflects a reclassification of instruments used in Duke Capital’s cash management program from Cash and Cash Equivalents to Short-term Investments of $608 million. This reclassification is to present certain auction rate securities and other highly-liquid instruments as short-term investments rather than as cash equivalents due to the stated tenor of the maturities of these investments. Corresponding changes were made to the Consolidated Statements of Cash Flows for the years ended December 31, 2003 and 2002, resulting in reductions of $608 million and $492 million, respectively, in amounts presented as Cash and Cash Equivalents. In the Consolidated Statements of Cash Flows, Cash and Cash Equivalents of $492 million at December 31, 2002 was also revised to reflect the reclassification of these instruments from Cash and Cash Equivalents to Short-term Investments (See Note 8 for further information).
Cash and Cash Equivalents. All highly liquid investments with original maturities of three months or less at the date of purchase are considered cash equivalents.
Short-term Investments. Duke Capital actively invests a portion of its available cash balances in various financial instruments, such as tax-exempt debt securities that frequently have stated maturities of 20 years or more and tax-exempt money market preferred securities. These instruments provide for a high degree of liquidity through features such as daily and seven day notice put options and 7, 28, and 35 day auctions which allow for the redemption of the investments at their face amounts plus earned income. As Duke Capital intends to sell these instruments within one year or less, generally within 30 days from the balance sheet date, they are classified as current assets. Duke Capital has classified all short-term investments that are debt securities as available-for-sale under Statement of Financial Accounting Standards (SFAS) No. 115, “Accounting For Certain Investments in Debt and Equity Securities,” and they are carried at fair market value. Investments in money-market preferred securities that do not have stated redemptions are accounted for at their cost, as they do not have readily determinable fair values. Realized gains and losses and dividend and interest income related to these securities, including any amortization of discounts or premiums arising at acquisition, are included in earnings at the time they are earned.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Inventory. Inventory consists primarily of materials and supplies; natural gas and natural gas liquid (NGL) products held in storage for transmission, processing and sales commitments. This inventory is recorded at the lower of cost or market value, primarily using the average cost method.
Components of Inventory
Accounting for Risk Management and Hedging Activities and Financial Instruments. Duke Capital uses a number of different derivative and non-derivative instruments in connection with its commodity price, interest rate and foreign currency risk management activities and its trading activities, including forward contracts, futures, swaps, options and swaptions. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, are recorded on the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions.
Effective January 1, 2003, in connection with the implementation of the remaining provisions of Emerging Issues Task Force (EITF) Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” Duke Capital designated all energy commodity derivatives as either trading or non-trading. Gains and losses for all derivative contracts that do not represent physical delivery contracts are reported on a net basis in the Consolidated Statements of Operations. For each of the Duke Capital’s physical delivery contracts that are derivatives, the accounting model and presentation of gains and losses, or revenue and expense in the Consolidated Statements of Operations is shown below.
(a)
An accounting term used by Duke Capital to refer to derivative contracts for which an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in the
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Consolidated Statements of Operations. This term is applied to trading and undesignated non-trading derivative contracts. As this term is not explicitly defined within U. S. GAAP, Duke Capital’s application of this term could differ from that of other companies.
(b)
An accounting term used by Duke Capital to refer to contracts for which there is generally no recognition in the Consolidated Statements of Operations for any changes in fair value until the service is provided, the associated delivery period occurs or there is hedge ineffectiveness. As discussed further below, this term is applied to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, as well as to non-derivative contracts used for commodity risk management purposes. As this term is not explicitly defined within U. S. Generally Accepted Accounting Principles, Duke Capital’s application of this term could differ from that of other companies.
Prior to January 1, 2003, unrealized and realized gains and losses on all energy trading contracts, as defined in EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” which included many derivative and non-derivative instruments, were presented on a net basis in Trading and Marketing Net Margin within Non-regulated Electric, Natural Gas, Natural Gas Liquids, and Other in the Consolidated Statements of Operations. While the income statement presentation of gains and losses, or revenues and expenses for each category of non-trading derivatives, as described above, remained consistent from 2002 to 2003, the definition of a trading and non-trading instrument changed from EITF Issue No. 98-10 to EITF Issue No. 02-03. Under EITF Issue No. 98-10, all energy derivative and non-derivative contracts were considered to be trading that were entered into by an entity’s energy trading operations, while under EITF Issue No. 02-03 an assessment is performed for each contract, and only those individual derivative contracts that are entered into with the intent of generating profits on short-term differences in price are considered to be trading. As a result, a significant number of derivatives previously classified as trading under EITF Issue No. 98-10 became classified as non-trading as of January 1, 2003. The significant reduction, as of January 1, 2003, in the volume of derivative and non-derivative contracts that were considered to be trading resulted in presentation of gains and losses, or revenues and expenses for many contracts on a gross basis in 2003 that were presented on a net basis in 2002.
Where Duke Capital’s derivative instruments are subject to a master netting agreement and the criteria of the Financial Accounting Standards Board (FASB) Interpretation No. 39 (FIN 39), “Offsetting of Amounts Related to Certain Contracts-An Interpretation of Accounting Principles Board (APB) Opinion No. 10 and FASB Statement No. 105,” are met, Duke Capital presents its derivative assets and liabilities, and accompanying receivables and payables, on a net basis in the accompanying Consolidated Balance Sheets.
Cash Flow and Fair Value Hedges. Qualifying energy commodity and other derivatives may be designated as either a hedge of a forecasted transaction or future cash flows (cash flow hedge) or a hedge of a recognized asset, liability or firm commitment (fair value hedge). For all hedge contracts, Duke Capital provides formal documentation of the hedge in accordance with SFAS No. 133. In addition, at inception and on a quarterly basis Duke Capital formally assesses whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. Duke Capital documents hedging activity by transaction type (futures/swaps) and risk management strategy (commodity price risk /interest rate risk).
Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are included in the Consolidated Statements of Member’s/Common Stockholder’s Equity and Comprehensive Income (Loss) as Accumulated Other Comprehensive Income (Loss) (AOCI) until earnings are affected by the hedged item. Duke Capital discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer
qualifies as an effective hedge, the derivative is subject to the Mark-to-Market Model of Accounting (MTM
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Model) prospectively. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the underlying contract is reflected in earnings; unless it is no longer probable that the hedged forecasted transaction will occur at which time associated deferred amounts in AOCI are immediately recognized in current earnings.
For derivatives designated as fair value hedges, Duke Capital recognizes the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings, to the extent effective, in the current period. All derivatives designated and accounted for as hedges are classified in the same category as the item being hedged in the Consolidated Statements of Cash Flows. In addition, all components of each derivative gain or loss are included in the assessment of hedge effectiveness.
Normal Purchase and Normal Sales. From July 1, 2001 through June 30, 2003, Duke Capital applied the normal purchase and normal sale scope exception in Derivative Implementation Group (DIG) Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity” to certain forward sale contracts to deliver electricity. In connection with the adoption of SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” on July 1, 2003, Duke Capital has elected to designate substantially all forward contracts to sell power entered into after July 1, 2003 as cash flow hedges. Contracts that were being accounted for under the normal purchases and normal sales exception under SFAS No. 133 as of June 30, 2003 continue to be accounted for under the normal purchase and normal sales exception as long as the requirements for applying the exception are met. If contracts cease to meet this exception, the fair value of the contracts is recognized on the Consolidated Balance Sheets and the contracts are accounted for using the MTM Model unless immediately designated as a cash flow or fair value hedge.
Valuation. When available, quoted market prices or prices obtained through external sources are used to measure a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on internally developed valuation techniques or models. For derivatives recognized under the MTM Model, valuation adjustments are also recognized in the Consolidated Statements of Operations.
Goodwill. Duke Capital evaluates the impairment of goodwill under the guidance of SFAS No. 142, “Goodwill and Other Intangible Assets.” Under this provision, goodwill is subject to an annual test for impairment. Duke Capital has designated August 31 as the date it performs the annual review for goodwill impairment for its reporting units. Under the provisions of SFAS No. 142, Duke Capital performs the annual review for goodwill impairment at the reporting unit level, which Duke Capital has determined to be an operating segment or one level below.
Impairment testing of goodwill consists of a two-step process. The first step involves a comparison of the fair value of a reporting unit with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves a comparison of the implied fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value of a reporting unit is below its carrying amount.
Duke Capital uses a discounted cash flow analysis to determine fair value. Key assumptions in the determination of fair value include the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, Duke Capital incorporates current market information, historical factors and fundamental analysis, and other factors into its forecasted commodity prices.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
During the quarter ended September 30, 2004, the date of the annual goodwill impairment test for Field Services was changed to August 31st from September 30th. August 31st was selected to perform the annual goodwill impairment test because this earlier date allows Field Services to complete the goodwill impairment test within the same quarter as the testing date. In addition, the change in date will be consistent with the annual goodwill impairment test date used by Duke Capital’s other business segments. The change in testing goodwill date did not delay, accelerate or avoid an impairment charge. Accordingly, management believes that the accounting change described above is to a date which is preferable under the circumstances.
Other Long-term Investments. Other long-term investments, primarily marketable securities held in the captive insurance investment portfolio, are classified as available-for-sale securities as management does not have the intent and ability to hold the securities to maturity, nor are they bought and held principally for selling them in the near term. The securities are reported at fair value on Duke Capital’s Consolidated Balance Sheets. Unrealized holding gains and losses, net of tax, on the available-for-sale securities are reflected in AOCI in Duke Capital’s Consolidated Balance Sheets until they are realized and reflected in net income.
Property, Plant and Equipment. Property, plant and equipment are stated at historical cost less accumulated depreciation. Duke Capital capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as it is incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method. The composite weighted-average depreciation rates were 3.85% for 2004, 3.85% for 2003 and 3.95% for 2002. Also, see “Allowance for Funds Used During Construction (AFUDC),” discussed below.
When Duke Capital retires its regulated property, plant and equipment, it charges the original cost plus the cost of retirement, less salvage value, to accumulated depreciation and amortization. When it sells entire regulated operating units, or retires or sells non-regulated properties, the cost is removed from the property account and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded as income, unless otherwise required by the applicable regulatory body.
Duke Capital recognizes asset retirement obligations in accordance with SFAS No. 143, “Accounting For Asset Retirement Obligations,” for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the estimated useful life of the asset.
Investments in Residential, Commercial, and Multi-Family Real Estate. Investments in residential, commercial and multifamily real estate are carried at cost, net of any related depreciation, except for any properties meeting the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets,” to be presented as Assets Held for Sale. Proceeds from sales of residential properties are presented within Operating Revenues and the cost of properties sold are included in Operation, Maintenance and Other in the Consolidated Statements of Operations. Cash flows related to the acquisition, development and disposal of residential properties are included in Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows. Gains and losses on sales of commercial and multifamily properties as well as “legacy” land sales are presented as such in the Consolidated Statements of Operations, and cash flows related to these activities are included in Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Long-Lived Asset Impairments, Assets Held For Sale and Discontinued Operations. Duke Capital evaluates whether long-lived assets, excluding goodwill, have been impaired when circumstances indicate the carrying value of those assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used for developing estimates of future undiscounted cash flows. If the carrying value of the long-lived asset is not recoverable based on these estimated future cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value.
Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one source. Sources to determine fair value include, but are not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as changes in commodity prices or the condition of an asset, or a change in management’s intent to utilize the asset would generally require management to re-assess the cash flows related to the long-lived assets.
Duke Capital uses the criteria in SFAS No. 144 to determine when an asset is classified as held for sale. Upon classification as held for sale, the long-lived asset or asset group is measured at the lower of its carrying amount or fair value less cost to sell, depreciation is ceased and the asset or asset group is separately presented on the Consolidated Balance Sheets.
If an asset or asset group held for sale or sold has clearly distinguishable operations and cash flows, and Duke Capital will not have significant continuing involvement in the operations after the disposal and cash flows of the assets sold have been eliminated from Duke Capital’s ongoing operations, then the related results of operations for the current and prior periods, including any related impairments, are reflected as Discontinued Operations in the Consolidated Statements of Operations, net of tax. If an asset held for sale does not qualify for discontinued operations classification, any impairments and gains or losses on sales are recorded in continuing operations as Losses on Sales of Other Assets, net in the Consolidated Statements of Operations. Impairments for all other long-lived assets, other than goodwill, are recorded as Impairment and Other Related Charges in the Consolidated Statements of Operations.
Captive Insurance Reserves. Duke Capital has captive insurance subsidiaries which provide insurance coverage to Duke Capital entities as well as certain third parties, on a limited basis, for various business risks and losses, such as workers compensation, property, business interruption and general liability. Liabilities include provisions for estimated losses incurred but not yet reported (IBNR) as well as provisions for known claims which have been estimated on a claims-incurred basis. IBNR reserve estimates involve the use of assumptions and are primarily based upon historical loss experience, industry data and other actuarial assumptions. Reserve estimates are adjusted in future periods as actual losses differ from historical experience. Intercompany balances and transactions are eliminated in consolidation.
Duke Capital’s captive insurance entities also have reinsurance coverage, which provides reimbursement to Duke Capital for certain losses above a per incident retention. Duke Capital’s captive insurance entities also have an aggregate stop-loss insurance coverage, which provides reimbursement from third parties to Duke Capital for its paid losses above certain per line of coverage aggregate amounts during a policy year. Duke Capital recognizes a reinsurance receivable for recovery of incurred losses under its captive’s reinsurance and stop-loss insurance coverage once realization of the receivable is deemed probable.
During 2004, Duke Capital eliminated intercompany reserves at its captive insurance subsidiaries of approximately $59 million which was a correction of an accounting error related to prior periods. In addition, a
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
$12 million pre-tax correction of an accounting error related to prior years was recorded. This correction was due to the recognition of reserves at Bison Insurance Company Limited (Bison) for reinsurance policies which have certain retrospective rating provisions.
Unamortized Debt Premium, Discount and Expense. Premiums, discounts and expenses incurred with the issuance of outstanding long-term debt are amortized over the terms of the debt issues. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate.
Environmental Expenditures. Duke Capital expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when environmental assessments and/or cleanups are probable and the costs can be reasonably estimated.
Cost-Based Regulation. Duke Capital accounts for certain of its regulated operations under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” The economic effects of regulation can result in a regulated company recording costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, Duke Capital records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Management continually assesses whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in the Consolidated Balance Sheets as Regulatory Assets and Deferred Debits, and Deferred Credits and Other Liabilities. Duke Capital periodically evaluates the applicability of SFAS No. 71, and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, companies may have to reduce their asset balances to reflect a market basis less than cost and write-off their associated regulatory assets and liabilities. (For further information see Note 4).
Guarantees. Duke Capital accounts for guarantees and related contracts, for which it is the guarantor, under FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In accordance with FIN 45, upon issuance or modification of a guarantee on or after January 1, 2003, Duke Capital recognizes a liability at the time of issuance or material modification for the estimated fair value of the obligation it assumes under that guarantee. Fair value is estimated using a probability-weighted approach. Duke Capital reduces the obligation over the term of the guarantee or related contract in a systematic and rational method as risk is reduced under the obligation. Any additional contingent loss for guarantee contracts is accounted for and recognized in accordance with SFAS No. 5, “Accounting for Contingencies.”
Duke Capital has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Capital’s maximum potential exposure under these indemnification agreements can range from a specified to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Duke Capital
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
is unable to estimate the total maximum potential amount of future payments under these indemnification agreements due to several factors, including uncertainty as to whether claims will be made.
Stock-Based Compensation. Duke Energy accounts for its stock-based compensation arrangements under the intrinsic value recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and FIN 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion No. 25).” Since the exercise price for all options granted under those plans was equal to the market value of the underlying common stock on the date of grant, no compensation cost is recognized in the accompanying Consolidated Statements of Operations. Restricted stock grants, phantom stock awards and certain stock-based performance awards are recorded over the required vesting period as compensation cost, based on the market value on the date of the grant. Other stock-based performance awards are recorded over the vesting period as compensation cost, and are adjusted for increases and decreases in market value up to the measurement date. Compensation expense for awards with pro-rata vesting is recognized in accordance with FIN 28, “Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans.”
The following table illustrates the effect on net (loss) income for Duke Capital, if Duke Energy had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to all stock-based compensation awards and reflects the provisions of SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure (an amendment to SFAS No. 123).”
Pro Forma Stock-Based Compensation
Revenue Recognition. Revenues on sales of natural gas, natural gas transportation, storage and distribution as well as sales of petroleum products, primarily at Natural Gas Transmission and Field Services, are recognized when either the service is provided or the product is delivered. Revenues related to these services provided or products delivered, but not yet billed, are estimated each month. These estimates are generally based on contract data, regulatory information, estimated distribution usage based on historical data adjusted for heating degree days, commodity prices and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month.
Crescent LLC (Crescent) sells residential developed lots in North Carolina, South Carolina, Georgia, Florida, Texas and Arizona. Crescent recognizes revenues from the sale of residential developed lots at closing. Profit is recognized under the full accrual method using estimates of average gross profit per lot within a project or phase of a project based on total estimated project costs. Land and land development costs are allocated to land sold based on relative sales values. Crescent recognizes revenues from commercial and multifamily project sales at closing using the full accrual method. Profit is recognized based on the difference between the sales price
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
and the carrying cost of the project. Crescent develops and sells condominium units in Florida, and revenue is recognized under the percentage-of-completion method.
AFUDC. AFUDC, recorded in accordance with SFAS No. 71, represent the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities, consists of two components, an equity component and an interest component. The equity component is a non-cash item. AFUDC is capitalized as a component of Property, Plant and Equipment Cost, with offsetting credits to the Consolidated Statements of Operations. After construction is completed, Duke Capital is permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in the Consolidated Statements of Operations was $17 million in 2004, which consisted of an equity component of $10 million and an interest expense component of $7 million. The total amount of AFUDC included in the Consolidated Statements of Operations was $54 million in 2003, which consisted of an equity component of $33 million and an interest expense component of $21 million. The total amount of AFUDC included in the Consolidated Statements of Operations was $25 million in 2002, which consisted of an equity component of $16 million and an interest expense component of $9 million.
Income Taxes. Duke Energy and its subsidiaries file a consolidated federal income tax return and other state and foreign jurisdictional returns as required. Federal income taxes have been provided by Duke Capital, with the exception of certain pass-through entities, on the basis of its separate company income and deductions in accordance with established practices of the consolidated tax group. Deferred income taxes have been provided for temporary differences between the GAAP and tax carrying amounts of assets and liabilities, with the exception of certain pass-through entities. These differences create taxable or tax-deductible amounts for future periods. Investment tax credits have been deferred and are being amortized over the estimated useful lives of the related properties.
Excise and Other Pass-Through Taxes. Duke Capital presents revenues net of pass-through taxes on the Consolidated Statements of Operations.
Segment Reporting. SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” establishes standards for a public company to report financial and descriptive information about its reportable operating segments in annual and interim financial reports. Operating segments are components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Two or more operating segments may be aggregated into a single operating segment provided aggregation is consistent with the objective and basic principles of SFAS No. 131, if the segments have similar economic characteristics, and the segments are considered similar under criteria provided by SFAS No. 131. SFAS No. 131 also establishes standards and related disclosures about the way the operating segments were determined, products and services, geographic areas and major customers, differences between the measurements used in reporting segment information and those used in the company’s general-purpose financial statements, and changes in the measurement of segment amounts from period to period. The description of Duke Capital’s reportable segments, consistent with how business results are reported internally to management and the disclosure of segment information in accordance with SFAS No. 131, are presented in Note 3.
Foreign Currency Translation. The local currencies of Duke Capital’s foreign operations have been determined to be their functional currencies, except for certain foreign operations whose functional currency has been determined to be the U.S. Dollar, based on an assessment of the economic circumstances of the foreign operation, in accordance with SFAS No. 52, “Foreign Currency Translation.” Assets and liabilities of foreign operations, except for those whose functional currency is the U.S. Dollar, are translated into U.S. Dollars at
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
current exchange rates. Translation adjustments resulting from fluctuations in exchange rates are included as a separate component of AOCI. Revenue and expense accounts of these operations are translated at average exchange rates prevailing during the year. Transaction gains and losses, which were not material for all periods presented, are included in the results of operations of the period in which they occur. Deferred taxes are not provided on translation gains and losses where Duke Capital expects earnings of a foreign operation to be permanently reinvested. Gains and losses relating to derivatives designated as hedges of the foreign currency exposure of a net investment in foreign operations are reported in foreign currency translation as a separate component of AOCI.
Cumulative Effect of Changes in Accounting Principles. As of January 1, 2003, Duke Capital adopted the remaining provisions of EITF Issue No. 02-03 and SFAS No. 143, “Accounting for Asset Retirement Obligations.” In accordance with the transition guidance for these standards, Duke Capital recorded a net-of-tax and minority interest cumulative effect adjustment for change in accounting principles of $133 million as a reduction in earnings.
In October 2002, the EITF reached a final consensus on EITF Issue No. 02-03. Primarily, the final consensus provided for (1) the rescission of the consensus reached on EITF Issue No. 98-10, (2) the reporting of gains and losses on all derivative instruments considered to be held for trading purposes to be shown on a net basis in the income statement, and (3) gains and losses on non-derivative energy trading contracts to be similarly presented on a gross or net basis, in connection with the guidance in EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.”
As a result of the consensus on EITF Issue No. 02-03, Duke Capital recorded a cumulative effect adjustment of $123 million (net of tax and minority interest) in the first quarter 2003 as a reduction to earnings. The recorded value on January 1, 2003 of all non-derivative energy trading contracts that existed on October 25, 2002 were written-off and inventories that were recorded at fair values were adjusted to historical cost. Adopting the final consensus on EITF Issue No. 02-03 did not require a change to prior periods and, therefore, Duke Capital did not change the 2002 classification of operating revenue and operating expense amounts.
In June 2001, the FASB issued SFAS No. 143, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. For obligations related to non-regulated operations, a cumulative effect adjustment of $10 million (net of tax and minority interest) was recorded in the first quarter of 2003, as a reduction in earnings.
New Accounting Standards. The following new accounting standards were adopted by Duke Capital during the year ended December 31, 2004 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:
FIN 46, “Consolidation of Variable Interest Entities.” In January 2003, the FASB issued FIN 46 which requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. FIN 46 defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. The primary beneficiary absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. In December 2003, the FASB issued FIN 46 (Revised December 2003) (FIN 46R), “Consolidation of Variable Interest Entities-An Interpretation of ARB No. 51,” which supercedes and amends the provisions of FIN 46. While FIN 46R retains many of the concepts and
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
provisions of FIN 46, it also provides additional guidance and additional scope exceptions, and incorporates FSP’s related to the application of FIN 46.
The provisions of FIN 46 applied immediately to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003, while the provisions of FIN 46R were required to be applied to those entities, except for special purpose entities, by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for Duke Capital). For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 or FIN 46R was required to be applied to special-purpose entities by the end of the first reporting period ending after December 15, 2003 (December 31, 2003 for Duke Capital), and was required to be applied to all other non-special purpose entities by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for Duke Capital).
Duke Capital has not identified any material variable interest entities created, or interests in variable entities obtained, after January 31, 2003, which require consolidation or disclosure under FIN 46R. Under the provisions of FIN 46R, effective March 31, 2004, Duke Capital has consolidated certain non-special purpose operating entities, previously accounted for under the equity method of accounting. These entities, which are substantive entities, had total assets of approximately $230 million as of December 31, 2004. In addition, as of December 31, 2004 and 2003, Duke Capital has recorded Net Property, Plant and Equipment of $112 million and $112 million, respectively, and Long-term Debt of $168 million and $157 million, respectively, on the Consolidated Balance Sheets, associated with a variable interest entity that is consolidated by Duke Capital. Duke Capital leases a natural gas processing plant from this entity, and retains all rights and obligations associated with the operations of this plant. This variable interest entity was consolidated on Duke Capital’s Consolidated Financial Statements prior to March 31, 2004 (the effective date of FIN46R) primarily due to Duke Capital’s guarantee of the residual value of the assets. The impact of consolidating these entities on Duke Capital’s Consolidated Financial Statements was not material. Duke Capital adopted the provisions of FIN 46R on December 31, 2003, related to its special-purpose entities consisting of its remaining trust subsidiaries that issued trust preferred securities. Since Duke Capital is not the primary beneficiary of those trust subsidiaries, those entities have been deconsolidated in the accompanying Consolidated Financial Statements. Interest paid to the subsidiary trust is classified as Interest Expense in the accompanying Consolidated Statements of Operations for periods after December 31, 2003. The preferred securities issued by these trusts were repaid during 2004. Additionally, Duke Capital previously had a significant variable interest in, but was not the primary beneficiary of Duke COGEMA Stone & Webster LLC (DCS). However, due to certain contract clarifications pursuant to a contract amendment entered into in April 2004, Duke Capital no longer holds a significant variable interest in DCS.
Various changes and clarifications to the provisions of FIN 46 have been made by the FASB since its original issuance in January 2003. While not anticipated at this time, any additional clarifying guidance or further changes to these complex rules could have an impact on Duke Capital’s Consolidated Financial Statements.
SFAS No. 132 (Revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” In December 2003, the FASB revised the provisions of SFAS No. 132 to include additional disclosures related to defined-benefit pension plans and other defined-benefit post-retirement plans, such as the following:
•
The long-term rate of return on plan assets, along with a narrative discussion on the basis for selecting the rate of return used
•
Information about plan assets for each major asset category (i.e. equity securities, debt securities, real estate, etc.) along with the targeted allocation percentage of plan assets for each category and the actual allocation percentages at the measurement date
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
•
The amount of benefit payments expected to be paid in each of the next five years and the following five-year period in the aggregate
•
The current best estimate of the range of contributions expected to be made in the following year
•
The accumulated benefit obligation for defined-benefit pension plans
•
Disclosure of the measurement date utilized.
Additionally, interim reports require additional disclosures related to the components of net periodic pension costs and the amounts paid or expected to be paid to the plan in the current fiscal year, if materially different than amounts previously disclosed. The provisions of SFAS No. 132R do not change the measurement or recognition provisions of defined-benefit pension and post-retirement plans as required by previous accounting standards. The provisions of SFAS No. 132R were applied by Duke Capital effective December 31, 2003 with the interim period disclosures applied beginning with the quarter ended March 31, 2004, except for the disclosure provisions of estimated future benefit payments which were effective for Duke Capital for the year ended December 31, 2004. (See Note 19 for the additional related disclosures).
FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” In May 2004, the FASB staff issued FSP FAS 106-2, which superseded FSP FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” FSP FAS 106-2 provides accounting guidance for the effects of the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Modernization Act). The Modernization Act introduced a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care benefit plans that include prescription drug benefits. FSP FAS 106-2 requires a sponsor to determine if its prescription drug benefits are actuarially equivalent to the drug benefit provided under Medicare Part D as of the date of enactment of the Modernization Act, and if it is therefore entitled to receive the subsidy. If a sponsor determines that its prescription drug benefits are actuarially equivalent to the Medicare Part D benefit, the sponsor should recognize the expected subsidy in the measurement of the accumulated postretirement benefit obligation (APBO) under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Any resulting reduction in the APBO is to be accounted for as an actuarial experience gain. The subsidy’s reduction, if any, of the sponsor’s share of future costs under its prescription drug plan is to be reflected in current-period service cost.
The provisions of FSP FAS 106-2 were effective for the first interim period beginning after June 15, 2004. Duke Capital adopted FSP FAS 106-2 retroactively to the date of enactment of the Modernization Act, December 8, 2003, as allowed by the FSP.
FSP FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004”. On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the “Act”). The Act provides a deduction for income from qualified domestic production activities, which will be phased in from 2005 through 2010.
Under the guidance in FSP FAS 109-1, which was issued in December 2004, the deduction will be treated as a “special deduction” as described in SFAS No. 109. As such, for Duke Capital, the special deduction had no material impact on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the periods in which the deductions are claimed on the tax returns.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004”. In addition to the qualified domestic production activities deduction discussed above, the Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for certain dividends from controlled foreign corporations. FSP FAS 109-2, which was issued in December 2004, states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings, as it applies to the application of SFAS No. 109. Although the deduction is subject to a number of limitations and some uncertainty remains as to how to interpret numerous provisions in the Act, Duke Capital believes that it has the information necessary to make an informed decision on the impact of the Act on its repatriation plans. Based on that decision, Duke Capital plans to repatriate approximately $500 million in extraordinary dividends, as defined in the Act, and accordingly has recorded a corresponding tax liability of $5 million as of December 31, 2004. However, Duke Capital has not provided for U.S. deferred income taxes or foreign withholding tax on basis differences in our non-U.S. subsidiaries that result primarily from undistributed earnings of approximately $75 million, which Duke Energy intends to reinvest indefinitely. Determination of the deferred tax liability on these basis differences is not practicable because such liability, if any, is dependent on circumstances existing if and when remittance occurs.
EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.” In March 2004, the EITF reached a consensus on Issue No. 03-1, which provides guidance on assessing whether impairments are other-than-temporary for marketable debt and equity securities accounted for under SFAS No. 115 and non-marketable equity securities accounted for under the cost method. The consensus also requires certain disclosures about unrealized losses that have not been recognized in earnings as other-than-temporary impairments. The disclosure provisions were effective for all periods ending after December 15, 2003. The other-than-temporary impairment application guidance was to be effective for reporting periods beginning after June 15, 2004.
In September 2004, the FASB issued FSP No. EITF Issue 03-1-1, “Effective Date of Paragraphs 10-20 of EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments”, which delays indefinitely the application of guidance provisions of EITF Issue No. 03-1 until further application guidance can be considered by the FASB. The FSP did not delay the effective date for the disclosure provisions of EITF No. 03-1. Duke Capital continues to monitor this issue; however, based upon developments to date does not expect the final guidance to have a material impact on its consolidated results of operations, financial position or cash flows.
The following accounting standards were adopted by Duke Capital during the year ended December 31, 2003 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:
SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” In April 2003, the FASB issued SFAS No. 149, which amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities, including the qualifications for the normal purchases and normal sales exception, under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” This amendment reflects decisions made by the FASB and the DIG process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 were to be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after September 30, 2003. The provisions of SFAS No. 149 which resulted from the DIG process and became effective in quarters beginning before June 15, 2003 continue to be applied based on their original effective dates. Duke Capital adopted the provisions of SFAS No. 149 on July 1, 2003. Certain modifications and changes
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
to the applicability of the normal purchase and normal sales scope exception for contracts to deliver electricity led Duke Capital to re-evaluate its accounting policy for forward sales contracts. As a result, Duke Capital elected to designate substantially all forward contracts to sell power entered into after July 1, 2003 as cash flow hedges on a prospective basis. Contracts that were being accounted for under the normal purchases and normal sales exception under SFAS No. 133 as of June 30, 2003 will continue to be accounted for under such exception, including any modifications to those contracts, as long as the requirements for applying the normal purchases and normal sales exception are met.
SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” In May 2003, the FASB issued SFAS No. 150 which establishes standards for classification and measurement of certain financial instruments with characteristics of both liabilities and equities. Under SFAS No. 150, those instruments are required to be classified as liabilities in the statement of financial position. The financial instruments affected include mandatorily redeemable stock, certain financial instruments that require or may require the issuer to buy back some of its shares in exchange for cash or other assets, and certain obligations that can be settled with shares of stock. SFAS No. 150 is effective for all financial instruments entered into or modified after May 31, 2003, and has been applied to Duke Capital’s existing financial instruments beginning July 1, 2003.
Duke Capital’s financial statements do not include any effects for the application of SFAS No. 150 to non-controlling interests in certain limited-life entities, which are required to be liquidated or dissolved on a certain date, based on the decision of the FASB in November 2003 to defer these provisions indefinitely with the issuance of FSP FAS 150-3, “Effective Date, Disclosures, and Transition for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests under SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” Duke Capital has a controlling interest in a limited-life entity in Bolivia, which is required to be liquidated 99 years after formation. A non-controlling interest in the entity is held by third parties. Upon termination or liquidation of the entity in 2094, the remaining assets of the entity are to be sold, the liabilities liquidated and any remaining cash distributed to the owners based upon their ownership percentages. As of December 31, 2004 the carrying value of the entity’s non-controlling interest of approximately $48 million approximates its fair value. Duke Capital continues to evaluate the potential significance of these aspects of SFAS No. 150, but does not anticipate this will have a material impact on Duke Capital’s consolidated results of operations, cash flows or financial position. SFAS No. 150 continues to be interpreted by the FASB and it is possible that significant future changes could be made by the FASB. Therefore, Duke Capital is not able to conclude whether such future changes would materially affect the amounts already recorded and disclosed under the provisions of SFAS No. 150.
EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease.” In May 2003, the EITF reached consensus in EITF Issue No. 01-08 to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to broaden the scope of arrangements accounted for as leases. EITF Issue No. 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is or includes a lease within the scope of SFAS No. 13, “Accounting for Leases.” Duke Capital has historically provided and leased storage capacity to outside parties, as well as entered into pipeline and electricity capacity agreements, both as the lessee and as a lessor. The accounting requirements under the consensus may impact the timing of revenue and expense recognition, and amounts previously reported as revenues may be required to be reported as rental or lease income. Should capital lease treatment be necessary, purchasers of transportation, electricity capacity and storage services are required to recognize assets on their balance sheets. The consensus is being applied prospectively to arrangements agreed to, modified, or acquired on or after July 1, 2003. Previous arrangements that would be leases or would contain a
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
lease according to the consensus will continue to be accounted for under historical accounting. The adoption of EITF Issue No. 01-08 did not have a material effect on Duke Capital’s consolidated results of operations, cash flows or financial position.
EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes.” In July 2003, the EITF reached consensus in EITF Issue No. 03-11 that determining whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis is a matter of judgment that depends on relevant facts and circumstances and the economic substance of the transaction. In analyzing those facts and circumstances, EITF Issue No. 99-19, “Reporting Revenue Gross as a Principle versus Net as an Agent,” and APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” should be considered. EITF Issue No. 03-11 was effective for transactions or arrangements entered into after September 30, 2003. The adoption of EITF Issue No. 03-11 did not have a material effect on Duke Capital’s consolidated results of operations, cash flows or financial position.
The following new accounting standards were issued, but have not yet been adopted by Duke Capital as of December 31, 2004:
SFAS No. 123 (Revised 2004), “Share-Based Payment”. In December of 2004, the FASB issued SFAS No. 123R, which replaces SFAS No. 123 and supercedes APB Opinion 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim or annual period after June 15, 2005. The pro forma disclosures previously permitted under SFAS 123 no longer will be an alternative to financial statement recognition. Under SFAS 123R, Duke Energy must determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost and the transition method to be used at the date of adoption. The transition methods include prospective and retroactive adoption options. Under the retroactive option, prior periods may be restated either as of the beginning of the year of adoption or for all periods presented. The prospective method requires that compensation expense be recorded for all unvested awards at the beginning of the first quarter of adoption of SFAS 123R, while the retroactive methods would record compensation expense for all unvested awards beginning in the first period restated.
Duke Energy continues to assess the transition provisions and has not yet determined the transition method to be used nor has Duke Energy determined if any changes will be made to the valuation method used for share-based compensation awards issued to employees in future periods. The impact to Duke Capital in periods subsequent to adopting SFAS 123R will be dependent upon the nature of any equity-based compensation awards issued to employees, but Duke Capital does not anticipate the adoption of SFAS 123R on July 1, 2005 to have any material impact on its consolidated results of operations, cash flows or financial position.
SFAS No. 153, “Exchanges of Nonmonetary Assets-an amendment of APB Opinion No. 29”, In December of 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS No. 153 also eliminates APB Opinion No. 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS No. 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. The impact to Duke Capital of SFAS No. 153 will depend on the nature and extent of any exchanges of
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
nonmonetary assets after the effective date, but Duke Capital does not currently expect SFAS No. 153 to have a material impact on its consolidated results of operations, cash flows or financial position.
EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations”. In November of 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS No. 144 have been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS No. 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus in EITF Issue No. 03-13 clarifies that the cash flows of the eliminated component are not considered to be eliminated if the continuing cash flows represent “direct” cash flows, as defined in the consensus. The consensus also requires that the assessment of whether significant continuing involvement exists be made from the perspective of the disposed component. The assessment should consider whether (a) the continuing entity retains an interest in the disposed component sufficient to enable it to exert significant influence over the disposed component’s operating and financial policies or (b) the entity and the disposed component are parties to a contract or agreement that gives rise to significant continuing involvement by the ongoing entity. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified as held for sale in fiscal periods beginning after December 15, 2004. The impact to Duke Capital of EITF Issue No. 03-13 will depend on the nature and extent of any long-lived assets disposed of or held for sale after the effective date, but Duke Capital does not currently expect EITF Issue No. 03-13 to have a material impact on its consolidated results of operations, cash flows or financial position.
2. Acquisitions and Dispositions
Acquisitions. Duke Capital consolidates assets and liabilities from acquisitions as of the purchase date, and includes earnings from acquisitions in consolidated earnings after the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair values on the date of acquisition. The purchase price minus the estimated fair value of the acquired assets and liabilities meeting the definition of a business as defined in EITF Issue No. 98-3, “Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business” is recorded as goodwill. The allocation of the purchase price may be adjusted if additional information on known contingencies existing at the date of acquisition becomes available within one year after the acquisition, and longer for certain income tax items.
In the second quarter of 2004, Field Services acquired gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips for a total purchase price of approximately $80 million, consisting of $74 million in cash and the assumption of approximately $6 million of liabilities. As the acquired assets were not considered businesses under the guidance in EITF Issue No. 98-3, no goodwill was recognized in connection with this transaction.
In the third quarter of 2004, Field Services acquired additional interest in three separate entities (for which Duke Energy Field Services LLC (DEFS) owned less than 100%, but had been consolidating) for a total purchase price of $4 million, and the exchange of some Field Services’ assets. Two of these acquisitions, Mobile Bay Processing Partners (MBPP) and Gulf Coast NGL Pipeline, LLC (GC), resulted in 100% ownership by Field Services. The MBPP transaction involved MBPP transferring certain long-lived assets to El Paso Corporation for El Paso Corporation’s interest in MBPP. As a result of this non-monetary transaction, the assets transferred were written-down to their estimated fair value which resulted in Duke Capital recognizing a pretax impairment of approximately $13 million, which was approximately $4 million net of minority interest, which is discussed in
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Note 11. An additional 12% interest in Dauphin Island Gathering Partners (DIGP) was also purchased for $2 million, which resulted in 84% ownership by Field Services. MBPP owns processing assets in the Gulf Coast. GC owns a 16.67% interest in two equity investments. DIGP owns gathering and transmission assets in the Gulf Coast.
The pro forma results of operations for these acquisitions do not materially differ from reported results.
On March 14, 2002, Duke Capital acquired Westcoast Energy Inc. (Westcoast) for approximately $8 billion, including the assumption of $4.7 billion of debt. In the transaction, a Duke Capital subsidiary acquired all of the outstanding common shares of Westcoast in exchange for approximately $1.7 billion in cash (net of cash acquired) and approximately 49.9 million shares of Duke Energy common stock (including exchangeable shares of a Duke Energy Canadian subsidiary that are substantially equivalent to and exchangeable on a one-for-one basis for Duke Energy common stock). The value of the Duke Energy common stock issued was approximately $1.7 billion and was determined based on the average market price of Duke Energy’s common shares over the two-day period before and after the terms of the transaction became fixed, in accordance with EITF Issue No. 99-12, “Determination of the Measurement Date for the Market Price of Acquirer Securities Issued in a Purchase Business Combination.” Under prorating provisions of the acquisition agreement that ensured that approximately 50% of the total consideration was paid in cash and 50% in stock, each common share of Westcoast entitled the holder to elect to receive 43.80 in Canadian dollars, or either 0.7711 of a share of Duke Energy common stock or of an exchangeable share of a Duke Energy Canadian subsidiary, or a combination thereof. The cash portion of the consideration was funded with the proceeds from the issuance of $750 million in mandatory convertible securities (Equity Units) in November 2001, along with incremental commercial paper. The commercial paper was repaid using the proceeds from the October 2002 public offering of Duke Energy Common Stock.
The acquisition of Westcoast was consistent with Duke Capital’s natural gas pipeline strategy to expand its footprint between key supply and market areas in North America. During its evaluation, Duke Capital identified revenue enhancement opportunities through expansion projects and business integration, cost reduction initiatives, and the divestiture of several non-strategic business lines and assets. These initiatives, when combined with the ongoing earnings contributions from Westcoast’s pipelines and distribution businesses, supported a purchase price in excess of the fair value of Westcoast’s assets, which resulted in the recognition of goodwill. The Westcoast acquisition was accounted for using the purchase method, and goodwill to the Natural Gas Transmission segment of approximately $2.3 billion was recorded in the transaction, of which approximately $57 million was expected to be deductible for income tax purposes. Of the $57 million, $52 million was allocated for tax purposes to Empire State Pipeline which was sold in February 2003.
During 2003, Duke Capital recorded additional purchase price adjustments as information regarding the assets acquired became available, including adjustments related to the sale of Empire State Pipeline and adjustments recorded to reflect the revised tax basis of certain acquired assets, with an offsetting increase to goodwill attributable to the acquisition.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
The following table summarizes the estimated fair values of the assets acquired and liabilities assumed as of the acquisition date, including the adjustments described above.
Purchase Price Allocation for Westcoast Acquisition
The following unaudited pro forma consolidated financial results are presented as if the acquisition had taken place at the beginning of the period presented.
Consolidated Pro Forma Results for Duke Capital, including Westcoast (unaudited)
Dispositions. The following table details proceeds from the sale of Duke Capital’s assets and businesses for 2004, 2003 and 2002.
Proceeds from Sales of Assets and Businesses
(a)
2004 includes approximately $840 million of debt assumed by buyer; 2003 includes $259 million of debt assumed by buyer
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
(b)
2003 includes $58 million of debt assumed by buyer
(c)
2004 includes $48 million note receivable from buyer; 2003 includes $70 million of debt assumed by buyer
(d)
Excludes investing activities related to sales and collections of notes receivable of $85 million for 2004, $243 million for 2003 and $204 million for 2002, and proceeds from sales of Crescent’s commercial and multi-family real estate of $606 million for 2004, $314 million for 2003, and $169 million for 2002
For the year ended December 31, 2004, the sale of other assets and businesses (which excludes assets held for sale as of December 31, 2004 and discontinued operations, both of which are discussed in Note 1, and sales by Crescent which are discussed separately below) resulted in approximately $937 million in cash proceeds plus a $48 million note receivable from the buyers, and net pre-tax losses of $240 million recorded in Losses on Sales of Other Assets, net and pre-tax losses of $4 million recorded in (Losses) Gains on Sales and Impairments of Equity Investments on the Consolidated Statements of Operations. (Losses) Gains on Sales and Impairments of Equity Investments includes a $23 million impairment charge, which is discussed in Note 11. Significant sales of other assets in 2004 are detailed as follows:
•
Natural Gas Transmission’s asset sales totaled $25 million in net proceeds. Those sales resulted in total pre-tax gains of approximately $33 million, of which $17 million was recorded in Losses on Sales of Other Assets, net and $16 million was recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations. Significant sales included the sale of storage gas related to the Canadian distribution operations, the sale of Natural Gas Transmission’s interest in the Millennium Pipeline, and the sale of land.
•
Field Services asset sales totaled $13 million in net proceeds. Those sales resulted in gains of $2 million which were recorded in Losses on Sales of Other Assets, net in the Consolidated Statements of Operations. These sales consisted of multiple small sales.
•
Duke Energy North America’s (DENA’s) asset sales totaled approximately $798 million in net proceeds and a $48 million note receivable. Those sales resulted in pre-tax losses of $248 million which were recorded in Losses on Sales of Other Assets, net in the Consolidated Statements of Operations. Significant sales included:
•
DENA’s eight natural gas-fired merchant power plants in the southeastern United States: Hot Spring (Arkansas); Murray and Sandersville (Georgia); Marshall (Kentucky); Hinds, Southaven, Enterprise and New Albany (Mississippi); and certain other power and gas contracts (collectively, the Southeast Plants). Duke Capital decided to sell the Southeast Plants in 2003, and recorded an impairment charge of $1.3 billion in 2003 since the assets’ carrying values exceeded their estimated fair values (see Note 11). The sale of those assets to KGen Partners LLC (KGen) obtained all required regulatory approvals and consents and closed on August 5, 2004. This transaction resulted in a pre-tax loss of approximately $360 million recorded in Losses on Sales of Other Assets, net in the 2004 Consolidated Statement of Operations. Nearly all of the loss was recognized in the first quarter of 2004 to reduce the assets’ carrying values to their estimated fair values, and approximately $4 million of the loss was recognized in the third quarter of 2004 upon closing. The fair value of the plants used for recording the loss in the first quarter was based on the sales price of approximately $475 million, as announced on May 4, 2004. The actual sales price consisted of $420 million of cash and a $48 million note receivable from KGen, which bears variable interest at the London Interbank Offered Rate (LIBOR) plus 13.625% per annum, compounded quarterly. The note is secured by a fourth lien on (i) substantially all of KGen’s assets and (ii) stock of KGen LLC (KGen’s owner), each subject to certain permitted liens and a first lien on cash in certain KGen accounts. The note matures with a balloon payment of all principal and interest due no later than 7 years and 6 months after the closing date. KGen has repaid the note as of March 15, 2005.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Duke Capital retains certain guarantees related to the sold assets. In conjunction with the sale, Duke Capital arranged a letter of credit with a face amount of $120 million in favor of Georgia Power Company, to secure obligations of a KGen subsidiary under a seven-year power sales agreement, commencing in May 2005, under which KGen will provide power from one of the plants to Georgia Power. Duke Capital is the primary obligor to the letter of credit provider, but KGen has an obligation to reimburse Duke Capital for any payments made by it under the letter of credit, as well as expenses incurred by Duke Capital in connection with the letter of credit. DENA will continue to provide services under a long-term operating agreement for one of the plants. As a result of DENA’s significant continuing involvement in the operations of the plants, this transaction did not qualify for discontinued operations presentation, as prescribed by SFAS No. 144. However, this continuing involvement does not prohibit sale accounting under SFAS No. 66, “Accounting for Sales of Real Estate.”
•
Some turbines and surplus equipment. This sale was anticipated in 2003 and therefore a loss of $66 million was recorded in Losses on Sales of Other Assets, net in the 2003 Consolidated Statement of Operations.
•
Some Duke Energy Trading and Marketing, LLC (DETM) contracts. DETM held a net liability position in those contracts and, as part of the sale, DETM paid a third party an amount approximating the carrying value of the contracts. The net cash payments of $99 million related to the sale of these assets are included in Cash Flows from Operating Activities. This resulted in a net loss of $65 million recorded in Losses on Sales of Other Assets, net in the 2004 Consolidated Statement of Operations.
•
A 25% undivided interest in DENA’s Vermillion facility. This sale was anticipated in 2003 and therefore losses of $18 million were recorded in Losses on Sales of Other Assets, net in the 2003 Consolidated Statement of Operations. Duke Capital still owns the remaining 75% interest in the Vermillion facility.
•
The partially completed Moapa facility to Nevada Power Company. This sale resulted in $186 million in net proceeds and a pre-tax gain of approximately $140 million recorded in Losses on Sales of Other Assets, net in the 2004 Consolidated Statement of Operations. An impairment charge for $515 million was recorded for this facility in 2003. This asset was not reported in Discontinued Operations in the Consolidated Statement of Operations as, among other considerations, it never entered into operations and had no associated historical operating revenues or significant costs.
•
The partially completed Luna facility to PNM Resources, Tucson Electric Power and Phelps Dodge Corporation. This sale resulted in net proceeds of $40 million and a pre-tax gain of $40 million recorded in Losses on Sales of Other Assets, net in the 2004 Consolidated Statements of Operations. An impairment charge for $270 million was recorded for this facility in 2003. This asset was not reported in Discontinued Operations in the Consolidated Statement of Operations as, among other considerations, it never entered into operations and had no associated historical operating revenues or significant costs.
•
On December 27, 2004, Duke Capital reached an agreement to sell its Grays Harbor partially completed facility to an affiliate of Invenergy LLC for $21 million plus other contingent considerations. Total sales proceeds and tax benefits for this transaction, excluding any potential contingent consideration, will be approximately $116 million. The sale is expected to be completed in the first or second quarter of 2005 and an approximate gain of $20 million will be reported in Losses on Sales of Other Assets, net in the Consolidated Statement of Operations. This
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
asset is not reported in Discontinued Operations in the Consolidated Statement of Operations as, among other considerations, it never entered into operations and had no associated historical operating revenues or significant costs. An impairment charge for $362 million was recorded for this facility in 2003. Effective December 31, 2004, Duke Capital terminated its capital lease associated with the dedicated pipeline which would have transported natural gas to the plant. This termination substantially offsets the expected proceeds and tax benefits from the sale of the partially completed Grays Harbor facility and resulted in a $20 million charge in 2004.
•
International Energy completed the sale of its 30% equity interest in Compañia de Nitrógeno de Cantarell, S.A. de C.V. (Cantarell) a nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico on September 8, 2004. The sale resulted in $60 million in net proceeds and an approximate $2 million pre-tax gain recorded to (Losses) Gains on Sales and Impairments of Equity Investments on the Consolidated Statements of Operations. A $13 million non-cash charge to Operation, Maintenance and Other expenses on the Consolidated Statements of Operations, related to a note receivable from Cantarell, was recorded in the first quarter of 2004.
•
Additional asset and business sales in 2004 totaled $41 million in net proceeds. Those sales resulted in net pre-tax losses of $10 million, of which a $11 million loss was recorded in Losses on Sales of Other Assets, net and a $1 million gain was recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations. Significant sales included Duke Energy Royal LLC’s interest in six energy service agreements and DukeSolutions Huntington Beach LLC.
For the year ended December 31, 2004, Crescent’s commercial and multi-family real estate sales resulted in $606 million of proceeds, and $192 million of net gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Significant sales included commercial project sales, resulting primarily from the sale of a commercial project in the Washington, D.C. area in March; real estate sales due primarily to the sale of the Alexandria and Arlington land tracts in the Washington, D.C. area; and several large land tract sales.
The sale of other assets and businesses for approximately $1,110 million in proceeds plus the assumption of $70 million of debt by the buyers for 2003 resulted in net losses of $115 million recorded in Losses on Sales of Other Assets, net on the Consolidated Statements of Operations, and gains of $279 million recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations. Significant sales of other assets and businesses in 2003 (other than discontinued operations as presented in Note 12, and sales which were recorded as purchase price adjustments to the Westcoast acquisition as presented above) are detailed by business segment as follows:
•
Natural Gas Transmission’s sales of assets and businesses totaled $610 million in proceeds, and the assumption of $70 million of debt by the buyers. Those sales resulted in gains of $90 million which were recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations, and gains of $7 million which were recorded in Losses on Sales of Other Assets, net in the Consolidated Statements of Operations. Significant sales included the sale of its remaining limited partnership interests in Northern Border Partners L.P.; the sale of its investments in the Alliance Pipeline and the associated Aux Sable NGL plant, Foothills Pipe Lines Ltd., and Vector Pipeline LP (Vector); the sale of Pacific Northern Gas Ltd., and the sale of two office buildings.
•
Field Services sales of assets totaled $141 million in proceeds. Those sales resulted in gains of $11 million which were recorded in (Losses) Gains on Sales and Impairments of Equity Investments in
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
the Consolidated Statements of Operations. Significant sales included Field Services’ Class B units of TEPPCO Partners, L.P.
•
DENA’s asset sales totaled $372 million in proceeds. The sale of DENA’s 50% ownership interest in Duke/UAE Ref-Fuel (Ref-Fuel) resulted in a gain of $178 million, which was recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations.
•
Impairment charges and net losses on sales, primarily related to the sale of DETM contracts, resulted in a net loss of $124 million, which was recorded in Losses on Sales of Other Assets, net in the Consolidated Statements of Operations. Impairment charges and losses on the DETM contracts resulted from DENA’s decision to wind-down DETM’s operations. As a result, DENA and ExxonMobil, its partner, are executing a reduction of DETM business in scope and scale and soliciting interest from selected parties for a significant portion of DETM’s contract portfolio. The ultimate financial impact to DENA of the reduction in the scope and sale of DETM and related liquidation of its contract portfolio cannot be reasonably estimated. However, it is possible that DENA will incur additional losses as a result of liquidating the DETM contracts.
The sale of other assets and businesses for approximately $150 million in gross proceeds for 2002 resulted in gains of $32 million recorded in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statement of Operations. Significant sales of other assets and businesses in 2002 are detailed by business segment as follows:
•
Natural Gas Transmission’s sales of assets totaled $81 million in proceeds. Those sales resulted in gains of $32 million, which were included in (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations. Significant sales included a portion of Natural Gas Transmission’s limited partnership interests in Northern Border Partners L.P.
•
Sales of assets and businesses previously included in Other totaled $69 million in proceeds with net gains and losses of zero. Significant sales included portions of Duke Engineering & Services, Inc. (DE&S) and DukeSolutions, Inc. (DukeSolutions) businesses.
3. Business Segments
Duke Capital operates the following business units: Natural Gas Transmission, Field Services, DENA, International Energy and Crescent. Duke Capital’s chief operating decision maker regularly reviews financial information about each of these business units in deciding how to allocate resources and evaluate performance. The entities under each business unit have similar economic characteristics, services, production processes, distribution methods and regulatory concerns. All of the Duke Capital business units are considered reportable segments under SFAS No. 131.
Natural Gas Transmission provides transportation and storage of natural gas for customers along the U.S. East Coast, the Southeast, and in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail customers in Ontario, and natural gas processing services to customers in Western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission, LLC. Duke Energy Gas Transmission, LLC’s natural gas transmission and storage operations in the U.S. are primarily subject to the Federal Energy Regulatory Commission’s (FERC’s) and the U.S. Department of Transportation’s (DOT’s) rules and regulations, while natural gas gathering, processing, transmission, distribution and storage operations in Canada are primarily subject to the rules and regulations of the National Energy Board (NEB) and the Ontario Energy Board (OEB). Texas Eastern Transmission LP (Texas Eastern) is an indirect subsidiary of Natural Gas Transmission and was also a separate Securities and Exchange Commission (SEC) reporting entity.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
On December 15, 2004 Texas Eastern announced that it filed a Form 15 with the SEC to suspend its reporting obligations under the Securities Exchange Act of 1934. The company is eligible to suspend its reporting obligation under the 1934 Act because it has fewer than 300 holders of record of any class of its securities.
Field Services gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, trades and markets, and stores NGLs. It conducts operations primarily through DEFS, which is approximately 30% owned by ConocoPhillips and approximately 70% owned by Duke Capital. Field Services gathers raw natural gas through gathering systems located in eight major natural gas producing regions: Permian Basin, Mid-Continent, ArklaTex, Gulf Coast, South, Central, Rocky Mountains and Western Canada. DEFS, which previously was a separate SEC reporting entity, announced January 31, 2005 that it filed a Form 15 with the SEC to suspend its reporting obligations under the Securities Exchange Act of 1934. DEFS is eligible to suspend its reporting obligations under the 1934 Act because it has fewer than 300 holders of record of any class of its securities.
In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to cause a Duke Capital subsidiary to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. Upon completion of this transaction, DEFS will be owned 50% by Duke Capital and 50% by ConocoPhillips. As a result, Duke Capital expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction. This transaction, which is subject to customary U.S. and Canadian regulatory approvals, is expected to close in the latter half of 2005. Additionally, in February 2005, DEFS sold its wholly-owned subsidiary, Texas Eastern Products Pipeline Company LLC (TEPPCO), the general partner of TEPPCO Partners, L.P., for approximately $1.1 billion and Duke Capital sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to Enterprise GP Holdings L.P. (EPCO), an unrelated third party. TEPPCO Partners, L.P. is a publicly traded master limited partnership which owns one of the largest common-carrier pipelines of refined petroleum products and liquefied petroleum gases in the United States, as well as natural gas gathering systems, petrochemical and NGL pipelines, and is engaged in crude oil transportation, storage, gathering and marketing. TEPPCO is responsible for the management and operations of TEPPCO Partners, L.P.
DENA operates and manages power plants and markets electric power and natural gas related to these plants and other contractual positions. DENA conducts business throughout the U.S. and Canada through Duke Energy North America, LLC and its 100% owned affiliates Duke Energy Marketing America, LLC and Duke Energy Marketing Canada Corp. DENA also participates in DETM. DETM is 40% owned by ExxonMobil Corporation and 60% owned by Duke Capital.
International Energy operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. and Canada. It conducts operations primarily through Duke Energy International, LLC and its activities target power generation in Latin America. Additionally, International Energy owns an equity investment in National Methanol Company, located in Saudi Arabia, which is a leading regional producer of methanol and methyl tertiary butyl ether (MTBE).
Crescent develops and manages high-quality commercial, residential and multi-family real estate projects primarily in the southeastern and southwestern United States. Some of these projects are developed and managed through joint ventures. Crescent also manages “legacy” land holdings in North and South Carolina.
The remainder of Duke Capital’s operations is presented as “Other”. While it is not considered a business segment, Other primarily includes certain unallocated corporate costs, DukeNet Communications, LLC (DukeNet), Bison and Duke Capital’s 50% interest in Duke/Fluor Daniel (D/FD). DukeNet develops, owns and
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
operates a fiber optic communications network, primarily in the Carolinas, serving wireless, local and long-distance communications companies, Internet service providers and other businesses and organizations. Bison’s principle activities, as a captive insurance entity, include the insurance and reinsurance of various business risks and losses, such as workers compensation, property, business interruption and general liability of subsidiaries and affiliates of Duke Capital. Bison also participates in reinsurance activities with certain third parties, on a limited basis. D/FD is a 50/50 partnership between subsidiaries of Duke Capital and Fluor Corporation. During 2003, Duke Capital and Fluor Corporation announced that they would dissolve the D/FD partnership. The D/FD partners adopted a plan for an orderly wind-down of the business which is expected to be completed by December 2005. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide. During 2003, Duke Capital decided to exit the merchant finance business conducted by Duke Capital Partners, LLC (DCP). DCP had been previously included in Other. At December 31, 2004, Duke Capital had exited the merchant finance business, and all of the results of operations for DCP have been classified as discontinued operations in the accompanying Consolidated Statements of Operations.
Duke Capital’s reportable segments offer different products and services and are managed separately as business units. Accounting policies for Duke Capital’s segments are the same as those described in Note 1. Management evaluates segment performance primarily based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT).
On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash, cash equivalents and short-term investments are managed centrally by Duke Capital, so the associated realized and unrealized gains and losses from foreign currency remeasurement and interest and dividend income on those balances, are excluded from the segments’ EBIT.
Transactions between reportable segments are accounted for on the same basis as revenues and expenses in the accompanying Consolidated Financial Statements.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Business Segment Data(a)
(a)
Segment results exclude results of entities classified as discontinued operations
(b)
Includes assets held for sale
(c)
Capital expenditures for residential properties are included in operating cash flows on the Consolidated Statement of Cash Flows. Capital expenditures for commercial and multi-family properties are included in investing cash flows on the Consolidated Statement of Cash Flows.
(d)
Includes interest income, foreign currency remeasurement gains and losses, and additional minority interest expense not allocated to the segment results.
(e)
Approximately, $2,035 million of Field Services revenues are from transactions with a single external customer.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Geographic Data
4. Regulatory Matters
Regulatory Assets and Liabilities. Duke Capital’s regulated operations are subject to SFAS No. 71. Accordingly, Duke Capital records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. (For further information see Note 1.)
Duke Capital’s Regulatory Assets and Liabilities (a):
(a)
All regulatory assets and liabilities are excluded from rate base unless otherwise noted.
(b)
Amounts are expected to be included in future rate filing.
(c)
Included in Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets
(d)
Included in rate base, earns a return
(e)
Included in Accounts Payable on the Consolidated Balance Sheets
(f)
Included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets
(g)
Recovery/refund is over the life of the associated asset or liability
(h)
$7 million to be refunded through 2007 and the remaining balance will be included in future rate filing
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
FERC Audits of Pre-Order 2004 Standards of Conduct. In September 2003, the FERC initiated a public audit of compliance with the pre-Order 2004 standards of conduct by Texas Eastern.
On February 28, 2005, the FERC approved a settlement agreement with regard to the Texas Eastern audit. The agreement includes a settlement payment of $500 thousand by Texas Eastern and a compliance plan under which Texas Eastern and its marketing affiliates will adopt certain new procedures.
The FERC’s findings have no material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.
Natural Gas Transmission. Rate Related Information. The British Columbia Pipeline System (BC Pipeline) and the field services business in western Canada recorded regulatory assets related to deferred income tax liabilities of approximately $612 million as of December 31, 2004 and $543 million as of December 31, 2003. Under the current NEB-authorized rate structure, income tax costs are recovered in tolls based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of timing differences that created the deferred income taxes, it is expected that the transportation and field services tolls will be adjusted to recover these taxes. Since most of these timing differences are related to property, plant and equipment costs, this recovery is expected to occur over a 20 to 30 year period.
When evaluating the recoverability of the BC Pipeline and the field services’ regulatory assets, management takes into consideration the NEB regulatory environment, natural gas reserve estimates for reserves located, or expected to be located, near these assets, the ability to remain competitive in the markets served, and projected demand growth estimates for the areas served by BC Pipeline and the field services business. Based on current evaluation of these factors, management believes that recovery of these tax costs is probable over the periods described above.
In November 2004, the NEB approved 2005 interim tolls for BC Pipeline to be effective January 1, 2005. BC Pipeline will file an application with the NEB for approval of final 2005 tolls under the 2004 settlement agreement in the first quarter of 2005.
Union Gas Limited (Union Gas) has rates that are approved by the OEB. Rates for the sale of gas are adjusted quarterly to reflect updated commodity price forecasts. The difference between the approved and the actual cost of gas incurred in the current period is deferred for future recovery from or return to customers, subject to approval by the OEB. These differences are directly flowed through to customers and, therefore, no rate of return is earned on the related deferred balances. The OEB’s review and approval of these gas purchase costs primarily considers the prudence of the costs incurred.
On December 15, 2004 the OEB approved the 2005 rates for Union Gas. The OEB also implemented an asymmetrical earnings sharing mechanism for Union Gas, effective January 1, 2005. Earnings in 2005, above the benchmark return on equity (ROE) determined through the OEB’s formulaic approach, normalized for weather, will be shared equally between ratepayers and Union Gas. No rate relief will be provided if Union Gas earns below the allowed ROE. Union Gas filed a Notice of Motion on December 22, 2004 to have the OEB reconsider its decision. On March 18, 2005, the OEB issued a decision to dismiss Union Gas’ Notice of Motion.
The OEB has proposed changes to the implementation dates for the Gas Distribution Access Rule (GDAR). GDAR provides the means by which gas vendors access gas distribution systems in Ontario. Union Gas was granted leave to appeal the vendor consolidated billing provisions of GDAR by the Court of Appeal for Ontario.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
On January 11, 2005, the Court of Appeal for Ontario dismissed the appeal. The OEB has proposed to defer the implementation of specific sections of the GDAR and to exempt gas distributors from the vendor consolidated billing provisions of the GDAR, subject to any person applying for the OEB to end the exemption.
Maritimes & Northeast Pipeline L.L.C. filed a rate case with the FERC on June 30, 2004 seeking an increase in rates from $0.695 per dekatherm (Dth) to $1.07/Dth. A FERC order accepted the rate filing and suspended the rates until January 1, 2005, when they became effective, subject to refund. The rate case has been set for hearing in 2005. Settlement discussions are ongoing.
Management believes that the effects of these matters will have no material adverse effect on Duke Capital’s future consolidated results of operations, cash flows or financial position.
International Energy. Brazil Regulatory Environment. In 2004, a new energy law was enacted in Brazil that changed the electricity sector’s regulatory framework. The new energy law created a regulated and non-regulated market that will coexist. The regulated market consists of auctions conducted by the government for the sale of power to the distribution companies. The distribution companies are required to fully contract their estimated electricity demand, principally through these regulated auctions. In the non-regulated market, generators, traders and non-regulated customers are permitted to enter into bilateral electricity purchase and sale contracts. The first regulated auction was held on December 7, 2004. In this auction, distribution companies contracted for their estimated demand for the period from 2005 to 2014. The contract structure within the auction process consisted of eight-year contracts with delivery periods commencing in each of the years 2005, 2006 and 2007. Duke Capital’s Brazilian affiliate, Duke Energy International, Geracao Paranapanema S.A., participated in this auction as a seller of electricity and was awarded eight-year contracts for delivery of 214 megawatts (MW) beginning in 2005, 58 MW for delivery beginning in 2006, and 218 MW for delivery beginning in 2007. During 2005, Duke Capital’s Brazilian affiliate may participate in the next regulated auction for the sale of power to the distribution companies. The auction process provides for eight year contracts with delivery commencing in 2008 and 2009.
5. Income Taxes
The following details the components of income tax expense (benefit) from continuing operations:
Income Tax Expense (Benefit) from Continuing Operations
(a)
Excludes $78 million of deferred federal, state and foreign tax benefits related to the cumulative effect of change in accounting principle recorded net of tax.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
The taxes recorded for discontinued operations are excluded from the continuing operations section above. They are presented as a separate column in Note 11.
Earnings (Loss) From Continuing Operations Before Income Taxes
Reconciliation of Income Tax Expense (Benefit) at the US Federal Statutory Tax Rate to the Actual Tax Expense (Benefit) from Continuing Operations (Statutory Rate Reconciliation)
During 2004, Duke Capital recorded a $52 million income tax benefit from the reduction of state and federal income tax reserves based on the resolution of several tax issues. The $52 million benefit is included in the Statutory Rate Reconciliation as follows: a $39 million state benefit is included in “State income tax, net of federal income tax effect” and a $13 million federal benefit is included in “Other items, net”.
On July 2, 2004, Duke Energy realigned certain subsidiaries resulting in all of its wholly owned merchant generation facilities being owned by a newly created entity, Duke Energy Americas LLC (DEA), a directly wholly owned subsidiary of Duke Capital. DEA and Duke Capital are pass-through entities for U.S. income tax purposes. As a result of these changes, Duke Capital recognized federal and state tax expense of approximately $1,030 million in the third quarter of 2004 from the elimination of the deferred tax assets that existed on its balance sheet prior to the July 2, 2004 reorganization. Correspondingly, Duke Energy, the parent of Duke Capital, reflected, through consolidation, the elimination of the $1,030 million deferred tax asset at Duke Capital and the creation of a deferred tax asset of approximately $1,030 million on its balance sheet. Duke Energy additionally recognized an approximate $48 million income tax benefit and corresponding deferred tax asset as a result of revaluing its deferred taxes to reflect a change in effective state tax rates.
The $1,030 million income tax expense is included in the Statutory Rate Reconciliation as follows: a $991 million expense is included in “Deferred taxes on restructuring of certain subsidiaries” and a $39 million expense is included in “State income tax, net of federal income tax effect”.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Net Deferred Income Tax Liability Components
The above amounts have been classified in the Consolidated Balance Sheets as follows:
Deferred Tax Liabilities
Valuation allowances have been established for certain foreign and state net operating loss carryforwards that reduce deferred tax assets to an amount that will, more likely than not, be realized. The net change in the total valuation allowance is included in “Tax differential on foreign earnings” and “State income tax, net of federal income tax effect” lines of the Statutory Rate Reconciliation.
Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes and other taxes have been made for potential liabilities resulting from such matters. As of December 31, 2004, Duke Capital has total provisions for uncertain tax positions of approximately $125 million as compared to $230 million as of December 31, 2003, which includes interest. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.
During 2004, Duke Energy recorded a $45 million income tax expense for the repatriation of approximately $500 million of foreign earnings that is anticipated to occur during 2005 related to the American Jobs Creation Act. Included in the $45 million is $5 million of foreign income tax expense recorded at Duke Capital. Deferred income taxes and foreign withholding taxes have not been provided on the remaining undistributed earnings of Duke Capital’s foreign subsidiaries as such amounts are deemed to be permanently reinvested. The cumulative undistributed earnings as of December 31, 2004 on which Duke Capital has not provided deferred income taxes and foreign withholding taxes, is approximately $75 million.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
6. Asset Retirement Obligations
In June 2001, the FASB issued SFAS No. 143 which addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. Asset retirement obligations at Duke Capital relate primarily to the retirement of certain gathering pipelines and processing facilities, the retirement of some gas-fired power plants, obligations related to right-of-way agreements and contractual leases for land use.
SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled.
In accordance with SFAS No. 143, Duke Capital identified certain assets that have an indeterminate life, and thus a future retirement obligation is not determinable. These assets included on-shore and some off-shore pipelines, certain processing plants and distribution facilities and some gas-fired power plants. A liability for these asset retirement obligations will be recorded when a fair value is determinable.
Upon adoption of SFAS No. 143, Duke Capital’s regulated natural gas operations classified removal costs for property that does not have an associated legal retirement obligation as a regulatory liability, in accordance with regulatory treatment. The total amount of removal costs included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets was $16 million as of December 31, 2004. The total amount of removal costs included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets was $17 million as of December 31, 2003.
SFAS No. 143 was effective for fiscal years beginning after June 15, 2002, and was adopted by Duke Capital on January 1, 2003. As of January 1, 2003, the implementation of SFAS No. 143 resulted in a net increase in total assets of $43 million, consisting primarily of an increase in net property, plant and equipment. Liabilities increased by $53 million, primarily representing the establishment of an asset retirement obligation liability of $69 million, reduced by the amount that was already recorded for cost of removal. A net-of-tax cumulative effect of a change in accounting principle adjustment of $10 million was recorded in the first quarter of 2003 as a reduction in earnings.
The pro forma net income effects of adopting SFAS No. 143 are not shown due to their immaterial impact.
The asset retirement obligation is adjusted each period for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows.
Reconciliation of Asset Retirement Obligation Liability
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
7. Risk Management and Hedging Activities, Credit Risk, and Financial Instruments
Duke Capital is exposed to the impact of market fluctuations in the prices of natural gas, electricity and other energy-related products marketed and purchased as a result of its ownership of energy related assets, interests in structured contracts and remaining proprietary trading activities. Exposure to interest rate risk exists as a result of the issuance of variable and fixed rate debt and commercial paper. Duke Capital is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. Duke Capital employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, futures, swaps, options and swaptions.
Duke Capital’s Derivative Portfolio Carrying Value as of December 31, 2004
The amounts in the table above represent the combination of amounts presented as assets and (liabilities) for Unrealized Gains and Losses on Mark-to-Market and Hedging Transactions on Duke Capital’s Consolidated Balance Sheets. All amounts in the table represent fair value except that certain hedging amounts include assets related to the application of the normal purchases and normal sales exception for electricity contracts of $160 million as of December 31, 2004. Duke Capital began applying the normal purchases and normal sales exception of DIG Issue C15 for electricity contracts July 1, 2001. For those contracts that were previously designated as cash flow hedges, Duke Capital treated the change as a de-designation under SFAS No. 133, and the fair value of each qualifying contract on July 1, 2001 became the contract’s net carrying amount. The contract’s net carrying amount will reduce upon settlement of the associated contracts over the next six years.
Commodity Cash Flow Hedges. Some Duke Capital subsidiaries are exposed to market fluctuations in the prices of various commodities related to their ongoing power generating and natural gas gathering, distribution, processing and marketing activities. Duke Capital closely monitors the potential impacts of commodity price changes and, where appropriate, enters into contracts to protect margins for a portion of future sales and generation revenues and fuel expenses. Duke Capital uses commodity instruments, such as swaps, futures, forwards and options, as cash flow hedges for natural gas, electricity and NGL transactions. Duke Capital is hedging exposures to the price variability of these commodities for a maximum of 13 years.
The ineffective portion of commodity cash flow hedges resulted in a gain of $3 million in 2004, a gain of $6 million in 2003, and a loss of $10 million in 2002, pre-tax, and is reported in the Non-Regulated Electric, Natural Gas, Natural Gas Liquids and Other line item on the Consolidated Statement of Operations. The amount recognized for transactions that no longer qualified as cash flow hedges was not material in 2004 or 2002 and was a gain of $297 million in 2003, pre-tax. The 2003 disqualified cash flow hedges were primarily associated with gas hedges related to DENA’s Southeast Plants and partially completed plants.
As of December 31, 2004, $313 million of the pre-tax deferred net gains on derivative instruments related to commodity cash flow hedges that were accumulated on the Consolidated Balance Sheet in a separate component
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
of Member’s/Common Stockholder’s Equity, in AOCI, and are expected to be recognized in earnings during the next 12 months as the hedged transactions occur. However, due to the volatility of the commodities markets, the corresponding value in AOCI will likely change prior to its reclassification into earnings.
Commodity Fair Value Hedges. Some Duke Capital subsidiaries are exposed to changes in the fair value of some unrecognized firm commitments to sell generated power or natural gas due to market fluctuations in the underlying commodity prices. Duke Capital actively evaluates changes in the fair value of such unrecognized firm commitments due to commodity price changes and, where appropriate, uses various instruments to hedge its market risk. These commodity instruments, such as swaps, futures and forwards, serve as fair value hedges for the firm commitments associated with generated power. For 2004, 2003, and 2002 the ineffective portion of commodity fair value hedges was reported in the Non-Regulated Electric, Natural Gas, Natural Gas Liquids, and Other line item on the Consolidated Statement of Operations and was not material. The amount recognized for transactions that no longer qualified as hedged firm commitments was not material in 2004 or 2002 and was a loss of $582 million, pre-tax, in 2003. The loss recorded in 2003, which primarily included amounts for certain contracts that were being accounted for as normal purchases and sales, was recognized due to management’s intent for DENA’s Southeast Plants and partially completed plants.
Normal Purchases and Normal Sales Exception. Duke Capital has applied the normal purchases and normal sales scope exception, as provided in SFAS No. 133 and interpreted by DIG Issue C15, to certain contracts involving the purchase and sale of electricity at fixed prices in future periods. These contracts, which relate primarily to the delivery of electricity over the next 11 years, are not included in the table above. As discussed in the preceding paragraph, a portion of the charge by DENA in 2003 related to contracts that were being accounted for as normal purchases and sales.
Interest Rate (Fair Value or Cash Flow) Hedges. Changes in interest rates expose Duke Capital to risk as a result of its issuance of variable-rate debt and commercial paper. Duke Capital manages its interest rate exposure by limiting its variable-rate and fixed-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. Duke Capital also enters into financial derivative instruments, including, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. Duke Capital’s existing interest rate derivative instruments and related ineffectiveness were not material to its consolidated results of operations, cash flows or financial position in 2004, 2003, and 2002.
Foreign Currency (Fair Value, Net Investment or Cash Flow) Hedges. Duke Capital is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be hedged through debt denominated or issued in the foreign currency. Duke Capital may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. During 2004, $43 million of net losses were included in the cumulative translation adjustment for hedges of net investments in foreign operations. During 2003, a $113 million net loss was included in the cumulative translation adjustment for hedges of net investments in foreign operations. During 2002, a $4 million net loss was included in the cumulative translation adjustment for hedges of net investments in foreign operations. To monitor its currency exchange rate risks, Duke Capital uses sensitivity analysis, which measures the impact of devaluation of foreign currencies.
Other Derivative Contracts. Trading. Duke Capital is exposed to the impact of market fluctuations in the prices of natural gas, electricity and other energy-related products marketed and purchased as a result of
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
proprietary trading activities. During 2003, Duke Capital prospectively discontinued proprietary trading and therefore the fair value of trading contracts as of December 31, 2004 relates to contracts entered into prior to the announced discontinuation of proprietary trading activities. Duke Capital’s exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms.
Undesignated. In addition, Duke Capital uses derivative contracts to manage the market risk exposures that arise from energy supply, structured origination, marketing, risk management, and commercial optimization services to large energy customers, energy aggregators and other wholesale companies, and to manage interest rate and foreign currency exposures. This category includes changes in fair value for derivatives that no longer qualify for the normal purchase and normal sales scope exception and disqualified hedge contracts, unless the derivative contract is subsequently re-designated as a hedge. The contracts in this category are primarily associated with forward power sales for the DENA Southeast Plants and partially completed Western Plants which were disqualified in 2003.
Credit Risk. Duke Capital’s principal customers for power and natural gas marketing and transportation services are industrial end-users, marketers, local distribution companies and utilities located throughout the U.S., Canada and Latin America. Duke Capital has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers and marketers throughout these regions. These concentrations of customers may affect Duke Capital’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, Duke Capital analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis.
Duke Capital’s industry has historically operated under negotiated credit lines for physical delivery contracts. Duke Capital frequently uses master collateral agreements to mitigate certain credit exposures, primarily in its trading and marketing and risk management operations. The collateral agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of an established threshold. The threshold amount represents an unsecured credit limit, determined in accordance with the corporate credit policy. Collateral agreements also provide that the inability to post collateral is sufficient cause to terminate contracts and liquidate all positions.
Collateral amounts held or posted may be fixed or may vary depending on the terms of the collateral agreement and the nature of the underlying exposure and generally covers trading, normal purchases and normal sales, and hedging contracts outstanding. Duke Capital may be required to return certain held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. In many cases, Duke Capital’s and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted. Likewise, downgrades in credit ratings of counterparties could require counterparties to post additional collateral to Duke Capital and its affiliates.
The change in market value of New York Mercantile Exchange (NYMEX)-traded futures and options contracts requires daily cash settlement in margin accounts with brokers.
Duke Capital also obtains cash or letters of credit from customers to provide credit support outside of collateral agreements, where appropriate, based on its financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.
Financial Instruments. The fair value of financial instruments not currently carried at market value is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
fair value. Accordingly, the estimates determined as of December 31, 2004 and 2003, are not necessarily indicative of the amounts Duke Capital could have realized in current markets.
Financial Instruments
(a)
Includes current maturities.
The fair value of cash and cash equivalents, short-term investments, notes and accounts receivable, notes and accounts payable and commercial paper are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates.
8. Marketable Securities
Short-term investments. At December 31, 2004 and 2003 Duke Capital had $1,135 million and $608 million, respectively of short-term investments consisting primarily of highly liquid tax-exempt debt securities. These instruments are classified as available-for-sale securities under SFAS No. 115 as management does not intend to hold them to maturity nor are they bought and sold with the objective of generating profits on short-term differences in price. The carrying value of these instruments approximates their fair value as they contain floating rates of interest. During 2004, Duke Capital purchased approximately $54,295 million and received proceeds on sale of approximately $53,768 million of short-term investments. During 2003, Duke Capital purchased approximately $24,097 million and received proceeds on sale of approximately $23,981 million of short-term investments. During 2002, Duke Capital purchased approximately $8,545 million and received proceeds on sale of approximately $8,053 million.
Other Long-term investments. Duke Capital also invests in debt and equity securities that are held in the captive insurance investment portfolio that are classified as available-for-sale under SFAS No. 115 and therefore are carried at estimated fair value based on quoted market prices. These investments are classified long-term as management does not intend to use them in current operations. Duke Capital’s captive insurance investment portfolio ($185 million at December 31, 2004) consists of approximately 66% debt securities, 21% cash and cash equivalent and 13% equity securities with a weighted average maturity of the debt securities of approximately 8 years. The cost of securities sold is determined using the specific identification method.
The estimated fair values of long-term investments classified as available-for-sale are as follows (in millions):
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
For the years ended December 31, 2004, 2003, and 2002 gains of approximately $3 million, $4 million and $4 million, respectively, were reclassified out of AOCI into earnings.
The following table provides the realized gains and losses, as well as gross proceeds from sale and gross purchases of the captive insurance investment portfolio (in millions):
9. Goodwill
Duke Capital evaluates the impairment of goodwill under the guidance of SFAS No. 142. As a result of the annual impairment tests required by SFAS No. 142, no charge for the impairment of goodwill was recorded in 2004.
In 2003, Duke Capital recorded a goodwill impairment charge of $254 million to write off all DENA goodwill, most of which related to DENA’s trading and marketing business. This impairment charge reflected the reduction in scope and scale of DETM’s business and the continued deterioration of market conditions affecting DENA during 2003. Duke Capital used a discounted cash flow analysis to determine fair value. Key assumptions in the analysis included the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, Duke Capital incorporated current market information, historical factors and fundamental analysis, and other factors into its forecasted commodity prices. This charge is recorded in the Consolidated Statements of Operations as Impairment of Goodwill.
In 2002, Duke Capital recorded a goodwill impairment charge of $194 million related to International Energy’s European trading and gas marketing business (European Business), substantially all of which was sold in the fourth quarter of 2003. Significant changes in the European market and operating results adversely affected Duke Capital’s outlook for this reporting unit. The exit of key market participants and a tightening of credit requirements were the primary drivers of this revised outlook. The fair value of the European reporting unit was estimated using a discounted cash flow analysis, which included key assumptions including the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, Duke Capital incorporated current market information, historical factors and fundamental analysis, and other factors in determining estimated future cash flows. This charge is recorded in the Consolidated Statements of Operations in Discontinued Operations-Net Operating Loss, net of tax. See Note 12 for further information regarding the European reporting unit and its treatment as discontinued operations in the Consolidated Statements of Operations.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Changes in the Carrying Amount of Goodwill
(a)
Amounts consist primarily of foreign currency translation and purchase price adjustments to prior year acquisitions.
(b)
Amount represents corporate goodwill that is allocated to DENA for the purpose of impairment testing pursuant to SFAS No. 142. As a result, the impairment charge in 2003 was recorded in the DENA segment.
(c)
Amounts were included in the disposal of a portion of a reporting unit within Natural Gas Transmission and International Energy.
10. Investments in Unconsolidated Affiliates and Related Party Transactions
Investments in domestic and international affiliates that are not controlled by Duke Capital, but over which it has significant influence, are accounted for using the equity method. Duke Capital received distributions of $139 million in 2004, $263 million in 2003, and $369 million in 2002 from those investments. These amounts are included in Other, assets within Cash Flows from Operating Activities on the Consolidated Statements of Cash Flows. Duke Capital’s share of net earnings from these unconsolidated affiliates is reflected in the Consolidated Statements of Operations as Equity in Earnings of Unconsolidated Affiliates. (See Note 2 for 2004 dispositions.)
As of December 31, 2004 and December 31, 2003, investments in affiliates were carried at approximately $91 million and $66 million, respectively, less than the amount of underlying equity in net assets (7% of total investment in affiliates as of December 31, 2004 and 5% as of December 31, 2003). This amount is related to the difference in the carrying amount and the underlying net assets of investments owned by Field Services. Such difference has been fully allocated to the respective investee’s long-lived assets and the amounts are being amortized into income over the life of the underlying related long-lived assets.
Natural Gas Transmission. As of December 31, 2004 investments primarily included a 50% interest in Gulfstream Natural Gas System, LLC (Gulfstream). Gulfstream is an interstate natural gas pipeline that extends from Mississippi and Alabama across the Gulf of Mexico to Florida. Although Duke Capital owns a significant
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
portion of Gulfstream, it is not consolidated as Duke Capital does not hold a majority of voting control or have the ability to exercise control over Gulfstream.
Field Services. As of December 31, 2004 investments primarily included a 33% interest in Discovery Producer, LLC, a natural gas gathering and processing system that includes a pipeline in the Gulf of Mexico and natural gas processing and fractionation facilities in Louisiana. As of December 31, 2004 Field Services also owned Texas Eastern Products Pipeline Company LLC (TEPPCO), the general partner of TEPPCO Partners, L.P., a publicly traded master limited partnership which owns and operates a network of pipelines, storage and terminal facilities for refined products, liquefied petroleum gases, petrochemicals, natural gas and crude oil. The general partner is responsible for the management and operations of TEPPCO. See Note 21 for subsequent events disclosure.
DENA. As of December 31, 2004 investments primarily included a 50% interest in Southwest Power Partners, LLC. Southwest Power Partners, LLC is a gas-fired combined-cycle facility in Arizona that serves markets in Arizona, Nevada and California. Although Duke Capital owns a significant portion of this investment, it is not consolidated as it does not hold a majority of voting control or have the ability to exercise control over this investment.
International Energy. As of December 31, 2004 investments primarily included a 25% indirect interest in National Methanol Company, which owns and operates a methanol and MTBE business in Jubail, Saudi Arabia. International Energy also has a 50% ownership in Compañia de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche), a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico, and a 38% ownership in Aguaytia, a natural gas facility in Peru.
Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican national oil company (PEMEX). The current five year GCSA expires on October 31, 2006 and PEMEX has the option to renew the GCSA for an additional four years. Campeche has made a renewal offer to PEMEX that has been initially rejected; however, discussions continue with PEMEX regarding renewal of the contract or other possible arrangements. If it is determined that the renewal will not take place or another economically viable arrangement is not found, the value of International Energy’s equity investment in Campeche would decline and such investment would be written down to its resulting fair value. International Energy’s estimated maximum exposure to this risk is potential impairment or other charges of $70 million.
Crescent. As of December 31, 2004 investments included various real estate development projects.
Other. As of December 31, 2004 investments primarily included participation in various construction and support activities for fossil-fueled generating plants through D/FD.
Investments in Unconsolidated Affiliates
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Equity in Earnings of Unconsolidated Affiliates
(a)
Includes equity investments at the corporate level and the elimination of 50% of the profit earned by D/FD on construction projects with DENA and Duke Power. D/FD is 50% owned by Duke Capital. See additional information in the Related Party Transactions section that follows.
Summarized Combined Financial Information of Unconsolidated Affiliates
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Related Party Transactions.
Balances due to or due from Duke Energy included in the Consolidated Balance Sheets as of December 31, 2004 and 2003 are as follows:
(a)
The balances are classified as Other Current Assets on the Consolidated Balance Sheets.
(b)
Advances receivable are classified as Other within Investments and Other Assets on the Consolidated Balance Sheets. The advances do not bear interest, are carried as open accounts and are not segregated between current and non-current amounts.
(c)
The balances are classified as Accounts Payable on the Consolidated Balance Sheets.
During the first half of 2004, Duke Capital received $160 million from Duke Energy as payment related to certain tax losses that were anticipated to be realized at Duke Capital during 2004. This $160 million is reflected in the 2004 Consolidated Statement of Cash Flows as changes from Taxes Accrued in net cash provided by operating activities. However, in connection with Duke Energy’s realignment of certain subsidiaries as of July 2, 2004, as discussed in Note 5, the related tax attributes were transferred to Duke Energy and therefore not realized at Duke Capital. Accordingly, the $160 million is presented in the December 31, 2004, Consolidated Balance Sheet as a component of the net advances receivable in Investments and Other Assets. Subsequent to the July 2, 2004 realignment of the subsidiaries, Duke Capital received an additional $107 million in advances from Duke Energy, which is reflected as a component of net cash used in financing activities in the 2004 Consolidated Statement of Cash Flows. Subsequent to December 31, 2004, Duke Energy forgave these advances of $267 million.
Included in the Consolidated Statements of Operations for 2004 are net expenses of $104 million primarily consisting of settlement expense to Duke Energy for crude, NGLs, and gas hedges as well as trading and marketing net margin. Operating revenues, including trading and marketing net margin and management fees, are $17 million for 2003 and $52 million for 2002 related to intercompany sales to Duke Energy.
NorthSouth Insurance Company Limited is a subsidiary of Bison which insures exposures of Duke Power Company, an unconsolidated affiliate of Duke Capital. No unearned premiums were recorded as of December 31, 2004. Included in Other Current Liabilities on the Consolidated Balance Sheets are unearned premiums of $8 million for 2003. Included in Non-Regulated Electric, Natural Gas, Natural Gas Liquids, and Other within the Consolidated Statements of Operations are earned premiums of approximately $16 million for 2004 and $8 million for 2003.
Outstanding notes receivable from unconsolidated affiliates were $89 million as of December 31, 2004 and $146 million as of December 31, 2003. Amounts are included in Notes Receivable on the Consolidated Balance Sheets. Of the notes outstanding as of December 31, 2004, $50 million related to International Energy’s note receivable from the Campeche project, a 50% owned joint venture, $25 million related to a note from a partnership in which Natural Gas Transmission has 50% ownership, and the remaining $14 million related to notes that Crescent had with partners in three of its joint ventures. These outstanding notes receivables had interest rates at or above current market rates.
International Energy loaned money to Campeche to assist in the costs to build. During 2004, International Energy received principal and interest payments of $7 million from Campeche, a 50% owned DEI affiliate. Payments from Campeche in 2003 and 2002 were $8 million and $1 million, respectively.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Natural Gas Transmission has a 50% ownership in two pipeline companies, Gulfstream, an operating pipeline, and Islander East, LLC, a development stage pipeline. In addition, DENA has a 50% ownership in a Canadian power plant, McMahon Cogeneration Plant, a cogeneration natural gas fired facility. Natural Gas Transmission provides certain administrative and other services to the pipeline companies and the Canadian power plant. Natural Gas Transmission recorded recoveries of costs from these affiliates of $8 million, $12 million, and $14 million during 2004, 2003, and 2002, respectively. The outstanding receivable from these affiliates was $1 million and $2 million for 2004 and 2003, respectively.
Firm capacity payments to Alliance Pipeline and Vector were $33 million and $30 million for 2003 and 2002, respectively. Natural Gas Transmission sold its ownership in these pipelines in 2003.
During 2002, Natural Gas Transmission recognized $28 million in earnings for a construction fee received from an unconsolidated affiliate related to the successful completion of Gulfstream.
Field Services sells a portion of its residue gas and NGLs to, purchases raw natural gas and other petroleum products from, and provides gathering and transportation services to unconsolidated affiliates (primarily TEPPCO). Total revenues from these affiliates were approximately $278 million, $166 million, and $138 million for 2004, 2003, and 2002, respectively. Total purchases from these affiliates were approximately $125 million, $98 million, and $82 million for 2004, 2003, and 2002, respectively. Total operating expenses were $4 million for 2004 and 2003 and $1 million for 2002.
D/FD is a 50/50 partnership between subsidiaries of Duke Capital and Fluor Corporation. During 2003, Duke Capital and Fluor Corporation announced that they would dissolve the D/FD partnership. The D/FD partners adopted a plan for an orderly wind-down of the business which is expected to be completed by December 2005. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide. D/FD was the primary builder of DENA’s merchant generation plants. Fifty percent of the profit earned by D/FD for the construction of affiliates’ generation plants, which is associated with Duke Capital’s ownership, is either deferred in consolidation until the plant is sold or, once the plant becomes operational, the deferred profit is amortized over the plant’s useful life or on an accelerated basis if the plants are impaired. Fifty percent of the profit earned by D/FD for operating and maintenance services for Duke Capital owned plants is eliminated in consolidation. For the year ended December 31, 2004, Duke Capital deferred profit of $2 million for D/FD construction contracts and did not eliminate any profit for operating and maintenance services. For the year ended December 31, 2003, Duke Capital deferred profit of $59 million for construction contracts and eliminated profit of less than one million for operating and maintenance services. For the year ended December 31, 2002, Duke Capital deferred profit of $159 million for construction contracts and eliminated profit of $3 million for operating and maintenance services. In addition, as part of the D/FD partnership agreement, excess cash is loaned at current market rates to Duke Capital and Fluor Enterprises, Inc. (See Note 14.)
In the normal course of business, Duke Capital’s consolidated subsidiaries enter into energy trading contracts or other derivatives with one another. On a separate company basis, each subsidiary accounts for such contracts as if they were transacted with a third party and records the contracts using the MTM Model or the Accrual Model of Accounting (Accrual Model), as applicable. For example, DETM may enter into a contract to purchase natural gas from DEFS. DEFS may record this contract using accrual accounting, while DETM may mark the contract to market through its current earnings. In the consolidation process, the effects of this intercompany contract are eliminated, and not reflected in Duke Capital’s Consolidated Financial Statements.
Also see Note 14, Debt and Credit Facilities, Note 16, Commitments and Contingencies, and Note 17, Guarantees and Indemnifications, and Note 21, Subsequent Events, for additional related party information.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
11. Impairment, Severance, and Other Related Charges
Field Services. In the third quarter of 2004, Field Services recorded impairments of approximately $22 million related to some of Field Services’ operating assets. The majority of this charge relates to the MBPP exchange transaction discussed in Note 2.
Additionally, in the third quarter of 2004, Field Services recorded an impairment of approximately $23 million related to equity method investments at Field Services. The impairment is included in (Losses) Gains on Sales and Impairments of Equity Investments on the Consolidated Statements of Operations. The impairment charge was related to management’s assessment of the recoverability of some equity method investments. Field Services determined that these assets, which are located in the Gulf Coast, were impaired; therefore they were written down to fair value. Fair value was determined based on management’s best estimates of sales value and/or discounted future cash flow models.
The 2002 charges were primarily to write-off inventory and other current assets to their net realizable value.
Crescent. In the fourth quarter of 2004, Crescent recorded impairment charges of approximately $42 million related to two residential developments in Payson, Arizona, the Rim and Chaparral Pines, and one residential development in Austin, Texas, Twin Creeks. The impairment charges were related to long lived assets at the three properties. The developments have suffered from slower than anticipated absorption of available inventory. Fair value of the assets was determined based on management’s assessment of current operating results and discounted future cash flow models. Crescent also recorded bad debt charges of $8 million related to notes receivable due from Rim Golf Investor, LLC and Chaparral Pines Investor, LLC. This amount is recorded in Operation, Maintenance and Other on the Consolidated Statement of Operations.
DENA. In the fourth quarter of 2003, as a result of deteriorating market conditions in the merchant energy industry, Duke Capital decided to exit the merchant power generation business in the Southeastern U.S. The carrying value of the Southeast Plants exceeded the fair value, resulting in an impairment charge in 2003 of approximately $1.3 billion. The fair value of the Southeast Plants was estimated primarily based on third party comparable sales, analysis from outside advisors and information available from efforts to sell certain of these assets. These assets were subsequently sold in the second quarter of 2004. (See Note 2.)
Also in the fourth quarter of 2003, Duke Capital decided not to fund completion of construction of three DENA merchant power plants located in Washington, Nevada and New Mexico (the deferred plants). The carrying value of these assets exceeded the fair value, resulting in an impairment charge in 2003 of approximately $1.1 billion. The fair value of the deferred plants was estimated based primarily on analysis from outside advisors and information available from efforts to sell certain of these assets. The deferred plants located in Nevada and New Mexico were sold in the fourth quarter of 2004. During 2004, Duke Capital reached an agreement to sell the partially completed plant located in Washington. (See Note 2.)
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
During 2003, Duke Capital agreed to sell a power generation plant in Maine and classified the asset as held for sale. The carrying value exceeded the negotiated sales price for the plant so an impairment charge of $72 million was recorded in 2003. Subsequently, in 2003, the anticipated transaction did not occur, and management decided not to sell the plant, thus removing the asset from held for sale.
DENA recorded additional impairment charges of $125 million in 2003, primarily associated with a change in the expected dispatch of Morro Bay, a plant in California, and a plan to sell an investment in Bayside Power LP (Bayside), an unconsolidated affiliate. Fair value of these assets was estimated based primarily on discounted cash flow analysis.
Certain forward power contracts related to the Southeast Plants and the deferred plants had been primarily designated as normal purchases and sales in accordance with SFAS No. 133. In addition, certain forward gas contracts related to the long-lived assets had been designated as cash flow hedges in accordance with SFAS No. 133. As a result of the change in management intent for the long-lived assets, the related forward power and gas contracts were de-designated as normal purchases and sales and hedges. As a result, a net charge of $262 million was recorded.
As a result of the decisions discussed above, DENA recorded impairment charges in 2003 of approximately $2.9 billion, primarily related to electric generation plants which are classified as Property, Plant and Equipment on the Consolidated Balance Sheets and to mark the derivative contracts to market value and reclassify the hedge amounts previously included in AOCI in accordance with SFAS No. 133.
The 2002 impairment and other related charges included a partial impairment of uninstalled turbines and the termination of other turbines on order. Additionally, charges were recorded in 2002 to impair one of DENA’s merchant power facilities, and write-off site development costs in California and an abandoned information technology system. Fair value of these assets was estimated based on comparable sales or discounted cash flow analysis.
International Energy. The 2002 charges were to write-off site development costs in Brazil and Bolivia, and to partially impair uninstalled turbines.
Other. The 2003 charges were due primarily to the abandonment of a corporate risk management information system, primarily due to DENA exiting the proprietary trading business and the reduction of scope and scale of DETM’s business.
During 2002, Duke Capital communicated a voluntary and involuntary severance program across all segments to align the business with market conditions during that period. Severance plans related to the program were amended effective August 1, 2004 and will apply to individuals notified of layoffs between that date and January 1, 2006. As of December 31, 2004, no additional substantial charges are expected to be incurred under the plan. Provision for severance is included in Operations, Maintenance and Other in the Consolidated Statements of Operations.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
(a)
Substantially all expected severance costs will be applied to the reserves within one year.
(b)
Provision in 2003 excludes $5 million of curtailment costs related to other post-retirement benefits.
(c)
Includes minority interest.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
12. Discontinued Operations and Assets Held for Sale
Discontinued Operations. The following table summarizes, by segment, the amounts classified as Discontinued Operations, net of tax, in the Consolidated Statements of Operations.
Field Services
In December 2004, based upon management’s assessment of the probable disposition of certain gathering, compression and transportation assets in Wyoming, Field Services classified these assets as “held for sale” in the Consolidated Balance Sheets as of December 31, 2004. The book value of these assets was written down by $4 million ($3 million net of minority interest) to $10 million, which represents the estimated fair value less cost to sell. The after tax loss and results of operations related to these assets were included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations. In February 2005, these assets were exchanged for certain gathering assets in Oklahoma of equivalent fair value.
In December 2004, Field Services sold gas system and treating plant assets in Southeast New Mexico and South Texas, respectively. Field Services sold these assets for proceeds of approximately $6 million, with the carrying value being approximately equal to the sales price. The after tax loss and related results of operations were included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations.
In September 2004, Field Services recorded an impairment charge of approximately $23 million ($16 million net of minority interest) related to management’s current assessment of some additional gathering,
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
processing, compression and transportation assets in Wyoming. The estimated fair value of these assets less cost to sell was $27 million and classified as “held for sale” in the Consolidated Balance Sheet as of December 31, 2004. The after tax loss and related results of operations were included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations. In the first quarter of 2005, Field Services sold these assets for proceeds of $28 million, with the carrying value being approximately equal to the sales price.
In February 2004, Field Services sold gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million resulting in an immaterial gain. The after tax gain and results of operations related to these assets were included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations.
In 2003, Field Services sold two packages of assets for a total sales price of $90 million. The after tax gain on these sales of $12 million and related operating results were included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations. The assets sold consisted of various gas processing plants and gathering pipelines in Mississippi, Texas, Alabama, Louisiana and Oklahoma.
DENA
On September 21, 2004 DENA signed a purchase and sale agreement with affiliates of Irving Oil Limited (Irving), under which Irving will purchase DENA’s 75% interest in Bayside. Irving had the right to terminate the agreement at any time prior to February 21, 2005. Irving did not terminate this agreement within the deadline specified and the terms of the purchase and sale agreement are now binding. Closing will occur upon receipt of required third party consents and regulatory approvals which are expected sometime in the second quarter 2005. As a result of the above agreement, DENA presented the $40 million net assets of Bayside as “held for sale” in the Consolidated Balance Sheets as of December 31, 2004. After considering the minority ownership in Bayside, DENA’s net investment in Bayside was $19 million at December 31, 2004. Bayside was consolidated with the adoption of FIN 46 on March 31, 2004. Therefore, Bayside’s operating results for the period April 1 to December 31, 2004 are included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations. Prior operating results, including the impairment of the investment in Bayside of $55 million recorded in 2003, are not included in Discontinued Operations, as Bayside was previously accounted for as an equity method investment.
International Energy
In 2003, International Energy restructured and began exiting its operations in Europe. International Energy sold its Dutch gas marketing business for $84 million and sold a power generation plant in France for $79 million. An after tax net gain of $11 million on these sales was included in Discontinued Operations-Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations. An income tax benefit of approximately $101 million was also recorded in 2003, primarily associated with the $194 million goodwill impairment recognized in 2002 for the gas marketing business in Europe, the 2003 sale of that business and certain other exit costs. This tax benefit was included in Discontinued Operations-Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.
Associated with the sale of the European Business, International Energy holds a receivable from Norsk Hydro ASA with a fair value of $68 million as of December 31, 2004 and $63 million as of December 31, 2003. This receivable is included in Receivables in the Consolidated Balance Sheets as of December 31, 2003 and 2004. In 2004, International Energy recorded a $14 million ($9 million after tax) allowance for the note based on management’s assessment of the probability of not collecting the entire note. The after tax loss was included in Discontinued Operations-Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
In order to eliminate exposure to international markets outside of Latin America and Canada, in 2003 International Energy decided to pursue a possible sale or initial public offering of International Energy’s Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business). As a result of this decision, International Energy recorded an after tax loss of $233 million during 2003, which represented the excess of the carrying value over the estimated fair value of the business, less estimated costs to sell. Fair value of the business was estimated based primarily on comparable third party sales and analysis from outside advisors. This after tax loss was included in Discontinued Operations-Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.
In the first quarter of 2004, International Energy determined it was likely that a bid in excess of the originally determined fair value would be accepted and thus recorded a $238 million after-tax gain related to International Energy’s Asia-Pacific Business. The after tax gain was included in Discontinued Operations-Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations and restored the loss recorded during the fourth quarter of 2003.
In April 2004, International Energy completed the sale of the Asia-Pacific Business to Alinta Ltd. for a gross sales price of approximately $1.2 billion (including $840 million debt retired by the buyer). This resulted in recording an additional $40 million after-tax gain in the second quarter of 2004. International Energy received approximately $390 million of cash proceeds, net of approximately $840 million of debt retired (as a non-cash financing activity) as part of the sale of the Asia-Pacific Business. In September 2004, International Energy repaid approximately $50 million of remaining Asia-Pacific debt from assets that were held in a fully-funded consolidated trust for the specific purpose of retiring the debt. The assets held in the consolidated trust were received from Alinta, Ltd. as part of the sale of the Asia-Pacific Business. The Asia-Pacific debt had been classified as Current and Non-Current Liabilities Associated with Assets Held for Sale in the Consolidated Balance Sheets as of December 31, 2003. All after tax gains related to this transaction and the results of operations for these assets are included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations.
In 2003, International Energy completed the sale of its 85.7% majority interest in P.T. Puncakjaya Power (PJP) in Indonesia for $78 million. The sale resulted in a reduction to Duke Capital’s consolidated indebtedness of $259 million. International Energy recorded an immaterial after tax loss on the sale, which was included in Discontinued Operations-Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.
Crescent
Crescent routinely develops real estate projects and operates those facilities until they are substantially leased and a sales agreement is finalized. Crescent has several projects with distinguishable operations and cash flows which will be eliminated upon their sale. In the case Crescent does not retain any significant continuing involvement after the sale, Crescent classifies the project as “discontinued operations” as required by SFAS No. 144.
In 2004, Crescent sold one apartment complex, two residential and two commercial properties resulting in sales proceeds of approximately $52 million. The $5 million after tax gain on these sales was included in Discontinued Operations-Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.
In 2003, Crescent sold three retail centers and one apartment complex, all located in Florida, for a total sales price of approximately $77 million. The $11 million after tax gain on these sales was included in Discontinued Operations-Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Other
During 2003, Duke Capital decided to exit the merchant finance business conducted by DCP. As a result, Duke Capital recorded an approximately $17 million after tax loss, which represents the excess of the carrying value of the notes receivable over the fair value, less costs to sell. Fair value of the notes receivable was estimated based primarily on discounted cash flow analysis. The after tax loss was included in Discontinued Operations-Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.
During 2004, Duke Capital received approximately $58 million from the sale or collection of all of DCP’s notes receivable. An immaterial after tax gain related to these transactions was included in Discontinued Operations-Net Gain (Loss) on Dispositions, net of tax, in the Consolidated Statements of Operations.
Assets Held for Sale. The following are significant items classified as “held for sale” in the Consolidated Balance Sheet as of December 31, 2004:
•
Some gathering, processing, compression and transportation assets owned by Field Services a
•
DENA’s Bayside facility b
•
International Energy’s European Business a
The following are significant items classified as “held for sale” in the Consolidated Balance Sheet as of December 31, 2003:
•
Some turbines and related equipment owned by DENA
•
International Energy’s European Business a
•
International Energy’s Asia-Pacific Business a
•
DCP’s merchant finance business a
a
Operating results for these businesses are classified as Discontinued Operations in the Consolidated Statements of Operations
b
Bayside was consolidated as a result of the adoption of FIN 46 on March 31, 2004. As a result, Bayside’s operating results for the period April 1 to December 31, 2004 are included in Discontinued Operations in the Consolidated Statements of Operations. Prior operating results are not included in Discontinued Operations.
The following table presents the carrying values of the major classes of assets and associated liabilities held for sale in the Consolidated Balance Sheets as of December 31, 2004 and 2003.
Summarized Balance Sheet Information for Assets and Associated Liabilities Held for Sale
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
13. Property, Plant and Equipment
(a)
Includes capitalized leases: $87 million for 2004 and $86 million for 2003.
(b)
Includes accumulated amortization of capitalized leases: $33 million for 2004 and $16 million for 2003.
Capitalized interest of $20 million for 2004, $77 million for 2003 and $193 million for 2002 is included in the Consolidated Statements of Operations.
14. Debt and Credit Facilities
Summary of Debt and Related Terms
(a)
Upon the implementation of SFAS No. 150, effective July 1, 2003, the trust preferred securities were reclassified to Long-term Debt from Guaranteed Preferred Beneficial Interests in Subordinated Notes of Duke Capital LLC or Subsidiaries. Additionally, upon the adoption of the provisions of FIN 46R as of
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
December 31, 2003, Duke Capital’s remaining trust subsidiary that had issued the trust preferred security was deconsolidated since Duke Capital was not the primary beneficiary of the trust subsidiary. This resulted in Duke Capital reflecting debt to the affiliate in the December 31, 2003 Long-term Debt balance. During 2004, the trust preferred security was redeemed for approximately $250 million.
(b)
The weighted-average days to maturity were 9 days as of December 31, 2004 and 6 days as of December 31, 2003.
(c)
As of December 31, 2004, $485 million of debt was denominated in Brazilian Reals with the principal indexed annually to Brazilian inflation and $3,720 million of debt was denominated in Canadian dollars. As of December 31, 2003, $437 million of debt was denominated in Brazilian Reals with the principal indexed annually to Brazilian inflation and $3,673 million of debt was denominated in Canadian dollars.
(d)
Balance at December 31, 2003 excludes approximately $890 million of long-term debt, notes payable and commercial paper denominated in Australian Dollars related to International Energy’s Asia-Pacific Business. As of December 31, 2003, International Energy’s Asia-Pacific Business was classified as discontinued operations, and the debt associated with the Asia-Pacific Business was reclassified to Current and Non-Current Liabilities Associated with Assets Held for Sale. During 2004, the debt was retired as part of the sale of the Asia-Pacific Business.
(e)
Weighted-average rates on outstanding short-term notes payable and commercial paper was 2.5% as of December 31, 2004 and 2.3% as of December 31, 2003.
Unsecured Debt. In February 2004, Duke Capital remarketed $875 million of senior notes due in 2006, underlying Duke Energy’s 8.25% Equity Units and reset the interest rate from 5.87% to 4.302%. As this action was contemplated in the original Equity Units issuance, the transaction had no immediate accounting implications. Subsequently, Duke Capital exchanged $475 million of the remarketed senior notes for $200 million of 4.37% senior unsecured notes due in 2009, and $288 million of 5.5% senior unsecured notes due in 2014. In accordance with EITF Issue No. 96-19, “Debtors Accounting for a Modification or Exchange of Debt Instruments,” the $475 million of remarketed senior notes issued earlier at 4.302% was extinguished. This exchange transaction resulted in an approximate $11 million loss, which was included in Interest Expense in the Consolidated Statements of Operations for the year ended December 31, 2004. Proceeds from the remarketed notes were used to purchase U.S. Treasury securities that were held by the collateral agent and, upon maturity, were used to satisfy the forward stock purchase contract component of the Duke Energy 8.25% Equity Units in May of 2004.
Additionally, Duke Capital remarketed $750 million of its 4.32% senior notes due in 2006, underlying Duke Energy’s 8.00% Equity Units on August 11, 2004. As a result of the remarketing, the interest rate on the notes was reset to 4.331%, effective August 16, 2004. Duke Capital subsequently exchanged $400 million of the 4.331% notes for $408 million of 5.668% notes due in 2014. This transaction resulted in an approximate $6 million loss, which was included in Interest Expense in the Consolidated Statements of Operations for the year end December 31, 2004. Proceeds from the remarketed notes were used to purchase U.S. Treasury securities held by the collateral agent and, upon maturity, were used to satisfy the forward stock purchase contract component of the Duke Energy 8% Equity Units in November 2004.
During 2004, Duke Capital purchased $202 million of its outstanding notes in the open market. These purchases included $140 million of Duke Capital 5.50% senior notes due March 1, 2014, $52 million of Duke Capital 4.37% senior notes due March 1, 2009 and $10 million of Duke Capital 6.75% senior noted due February 15, 2032. These securities were purchased at the then-current market price plus accrued interest.
Secured Debt. Other Assets Pledged as Collateral. As of December 31, 2004, secured debt consisted of various project financings, including Maritimes & Northeast Pipeline, LLC, Maritimes & Northeast Pipeline, LP (collectively, M&N Pipeline) and certain projects at Crescent. A portion of the assets, ownership interest and business contracts in these various projects are pledged as collateral.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Floating Rate Debt. Unsecured debt, secured debt and other debt included approximately $500 million of floating-rate debt as of December 31, 2004, and $1,745 million as of December 31, 2003. Floating-rate debt is primarily based on commercial paper rates or a spread relative to an index such as a London Interbank Offered Rate for debt denominated in U.S. dollars, and Banker’s Acceptances for debt denominated in Canadian dollars. As of December 31, 2004, the average interest rate associated with floating-rate debt was 2.7%.
In October 2004, Duke Capital prepaid a portion of a $994 million floating rate facility at DENA. The payment consisted of $565 million of principal, an associated $35 million working capital facility and accrued interest on the facilities. Additionally, in December 2004, Duke Capital repaid the remaining outstanding balance of $429 million.
Related Party Debt. Other debt included $17 million related to a loan with D/FD as of December 31, 2004, and $78 million as of December 31, 2003. As part of the D/FD partnership agreement, excess cash has been loaned, without stated repayment terms, at current market rates to Duke Capital and Fluor Enterprises, Inc. The weighted-average rate of this loan was 1.98% as of December 31, 2004 and 1.52% as of December 31, 2003. During 2003, Duke Capital and Fluor Corporation announced that they would dissolve the D/FD partnership. The D/FD partners have adopted a plan for an orderly wind-down of the business by December 2005. The entire outstanding balance of the loan with D/FD has been classified as Current Maturities of Long-term Debt and Preferred Stock on the December 31, 2004 and 2003 Consolidated Balance Sheets.
Upon the adoption of the provisions of FIN 46R as of December 31, 2003, as discussed in Note 1, Duke Capital’s remaining trust subsidiary that had issued the trust preferred security was deconsolidated since Duke Capital was not the primary beneficiary of the trust subsidiary. The deconsolidation of the remaining trust subsidiary resulted in Duke Capital reflecting debt to an affiliate of $258 million to the trust subsidiary in Long-term Debt on the December 31, 2003 Consolidated Balance Sheet. As of December 31, 2003, the debt to the affiliate consisted of $258 million of 8.375% notes due in 2029. During 2004, the issuance was redeemed for approximately $250 million. As the security was redeemed at par, security holders received $25 per each note held, plus accrued and unpaid distributions to the redemption date.
Maturities, Call Options and Acceleration Clauses.
Annual Maturities as of December 31, 2004
(a)
Excludes short-term notes payable and commercial paper of $68 million.
Annual maturities after 2009 include $200 million of long-term debt with call options, which provide Duke Capital with the option to potentially repay the debt early. Based on the years in which Duke Capital may first exercise its redemption options, it could potentially repay $100 million in 2005 and $100 million in 2007.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Available Credit Facilities and Restrictive Debt Covenants. As of December 31, 2004, credit facilities capacity was reduced by approximately $460 million compared to December 31, 2003, primarily related to the divested Asia-Pacific Business as discussed in Note 12. In addition, DEFS renewed and replaced its credit facility at a lower amount due to the reduced need for credit capacity. In October 2004, Duke Capital added two new credit facilities, including a $120 million bilateral credit facility with an expiration date of July 15, 2009 and a $130 million bilateral credit facility with an expiration date of October 18, 2007. Duke Capital intends to use both of these facilities for issuing letters of credit to support the business activities of its subsidiaries. The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the credit facilities.
Duke Capital’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2004, Duke Capital was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the credit agreements contain material adverse change clauses or any covenants based on credit ratings.
(a)
Credit facility contains an option allowing borrowing up to the full amount of the facility on the day of initial expiration for up to one year.
(b)
Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65%.
(c)
Credit facility contains an interest coverage covenant.
(d)
Credit facility is denominated in Canadian dollars, and was 100 million Canadian dollars as of December 31, 2004.
(e)
Credit facility is denominated in Canadian dollars, and was 200 million Canadian dollars as of December 31, 2004.
(f)
Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 75%. Credit facility is denominated in Canadian dollars, and was 300 million Canadian dollars as of December 31, 2004.
(g)
Credit facility contains an option at maturity allowing for the conversion of all outstanding loans to a term loan repayable up to one year after maturity date but not exceeding 18 months from the date of draw.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
(h)
Credit facility contains an option at maturity allowing for the conversion of all outstanding loans to a term loan repayable up to one year after maturity date.
(i)
Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 53%.
(j)
In December 2004, the credit facility expiration date was extended from March 2005 to May 2005.
(k)
Various credit facilities that support ongoing operations and miscellaneous transactions are not included in this credit facilities summary.
Preferred and Preference Stock of Duke Capital’s Subsidiaries. In June 2004, Westcoast redeemed all remaining outstanding Cumulative Redeemable First Preferred Shares, Series 6. The Series 6 Shares were redeemed for 25.00 per share in Canadian dollars plus all accrued and unpaid dividends to the date of redemption for a total redemption amount of approximately 104 million Canadian dollars.
In October 2004, Westcoast redeemed all remaining outstanding Cumulative Redeemable First Preferred Shares, Series 9. The Series 9 Shares were redeemed for 25.00 per share in Canadian dollars plus all accrued and unpaid dividends to the date of redemption for a total redemption amount of 125 million Canadian dollars.
Duke Capital has approximately $1,150 million of credit facilities which expire in 2005. It is Duke Capital’s intent to resyndicate the $1,150 million of expiring credit facilities.
15. Preferred and Preference Stock of Duke Capital’s Subsidiaries
In connection with the Westcoast acquisition in 2002, Duke Capital assumed approximately $411 million of authorized and issued redeemable preferred and preference shares at Westcoast and Union Gas. As of December 31, 2004 and 2003, these preferred and preference shares at Westcoast and Union Gas totaled $225 and $401 million, respectively. Since these preferred and preference shares are redeemable at the option of holder, as well as Westcoast and Union Gas, these preferred and preference shares do not meet the definition of a mandatorily redeemable instrument under SFAS No. 150. As such, these preferred and preference shares are considered contingently redeemable shares and are included in Minority Interests on the Consolidated Balance Sheets.
16. Commitments and Contingencies
General Insurance
Duke Capital carries, through its captive insurance company, Bison, and its affiliates, insurance and reinsurance coverages consistent with companies engaged in similar commercial operations with similar type properties. Duke Capital’s insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from Duke Capital’s operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, (4) financial services insurance policies in support of the indemnification provisions of the company’s by-laws and (5) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.
Bison is a member of Oil Insurance Limited (OIL) and sEnergy Insurance Limited (sEnergy), which provides property and business interruption reinsurance coverage respectively for Duke Capital’s facilities, and accounts for its membership under the cost method, as Duke Capital does not have the ability to exert significant influence. Should Bison terminate its membership in either OIL, sEnergy or both, it could be liable for additional
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
premium assessments. Bison continues to be a member of OIL and sEnergy in 2005 and purchases coverages provided by both companies.
Duke Capital also maintains excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The cost of Duke Capital’s general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.
Environmental
Duke Capital is subject to international, federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.
Remediation activities. Like others in the energy industry, Duke Capital and its affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of ongoing Duke Capital operations, sites formerly owned or used by Duke Capital entities, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve ground water remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary, as a function of site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, Duke Capital or its affiliates could potentially be held responsible for contamination caused by other parties. In some instances, Duke Capital may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliate operations. Management believes that completion or resolution of these matters will have no material adverse effect on consolidated results of operations, cash flows or financial position.
Clean Water Act. The Environmental Protection Agency’s (EPA’s) final Clean Water Act Section 316(b) rule became effective July 9, 2004. The rule establishes best technology available (BTA) requirements for existing steam electric generating facilities’ cooling water intake structures to protect fish and other aquatic organisms. Duke Capital’s three natural gas-fired generating facilities in California are affected sources under the rule. The rule requires a Comprehensive Demonstration Study (CDS) for each affected facility to generate information for use in determining necessary facility-specific BTA requirements and cost estimates for implementation. These studies will be completed over the next three to five years. Once compliance measures for a facility are determined and approved by regulators, each facility will typically have five or more years to implement the measures. Due to the wide range of BTA measures potentially applicable to a given facility, and since the final selection of compliance measures will be at least partially dependent upon the CDS information, Duke Capital is not able to estimate its cost for complying with the rule at this time.
Air Quality Control. In 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 (SIPs) to significantly reduce emissions of nitrogen oxide by May 1, 2003. The EPA rule was challenged in court by various states, industry and other interests, including Duke Energy. In 2000, the court upheld most aspects of the EPA rule. The same court subsequently extended the compliance deadline for emission reductions to May 31, 2004. Duke Capital has completed all necessary actions to meet the EPA rule and requirements, incurring approximately $3 million in capital costs for emission controls.
Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets were accruals related to extended
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
environmental-related activities of $76 million as of December 31, 2004 and $85 million as of December 31, 2003. The accrual for extended environmental-related activities represents Duke Capital’s provisions for costs associated with remediation activities at some of its current and former sites and other relevant environmental contingent liabilities. Management believes that completion or resolution of these matters will have no material adverse effect on consolidated results of operations, cash flows, or financial position.
Litigation
Western Energy Litigation. Since 2000, plaintiffs have filed 46 lawsuits in four western states against Duke Capital affiliates, current and former Duke Energy executives, and other energy companies. Most of the suits seek class-action certification on behalf of electricity and/or natural gas purchasers. The plaintiffs allege that the defendants manipulated the electricity and/or natural gas markets in violation of state and/or federal antitrust, unfair business practices and other laws. Plaintiffs in some of the cases further allege that such activities, including engaging in “round trip” trades, providing false information to natural gas trade publications and unlawfully exchanging information resulted in artificially high energy prices. Plaintiffs seek aggregate damages or restitution of billions of dollars from the defendants.
•
To date, one suit has been voluntarily dismissed by plaintiffs. Ten suits have been dismissed on filed rate and federal preemption grounds. The U.S. Ninth Circuit Court of Appeals has affirmed the dismissals of eight of these ten lawsuits. The plaintiff in one of the dismissed actions affirmed by the Ninth Circuit has petitioned the U.S. Supreme Court for certiorari and that court has invited the U.S. Solicitor General to give the United States’ views on whether certiorari should be granted. The plaintiffs in two of the ten dismissed actions filed appeals in March 2005.
•
In July 2004, Duke Energy reached an agreement in principle resolving the class-action litigation (the Western Power Class Action) involving the purchase of electricity filed on behalf of ratepayers and other electricity consumers in California, Washington, Oregon, Utah and Idaho. This agreement (the California Settlement) is part of a more comprehensive settlement involving FERC refunds and other proceedings. The class-action provisions of the California Settlement are subject to court approval. The California Settlement is addressed in more detail in the “Western Energy Regulatory Matters and Investigations” section below.
•
Suits filed on behalf of electricity ratepayers in other western states, on behalf of entities that purchased electricity directly from a generator and on behalf of natural gas purchasers, remain pending. It is not possible to predict with certainty whether Duke Capital will incur any liability or to estimate the damages, if any, that Duke Capital might incur in connection with these lawsuits, but Duke Capital does not presently believe the outcome of these matters will have a material adverse effect on its consolidated results of operations, cash flows or financial position.
Separately, in 2003, Pacific Gas and Electric Company (PG&E) initiated arbitration proceedings regarding disputes with DETM relating to amounts owed in connection with the termination of a bilateral power contract between the parties in early 2001. PG&E sought in excess of $25 million from DETM pursuant to a disputed “true-up” agreement between the parties. The PG&E true-up dispute was resolved in connection with the California Settlement.
In 2002, Southern California Edison Company (SCE) initiated arbitration proceedings regarding disputes with DETM relating to amounts owed in connection with the termination of bilateral power contracts between the parties in early 2001. SCE disputes DETM’s termination calculation and seeks in excess of $90 million. This dispute is not resolved in the California Settlement. Based on the level of damages claimed by the plaintiff and Duke Capital’s assessment of possible outcomes in this matter, Duke Capital does not expect that the resolution
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position.
Western Energy Regulatory Matters and Investigations. Duke Capital subsidiaries have been the subject, along with other energy suppliers and producers, of several investigations and regulatory proceedings at the state and federal levels that are looking into the causes of high wholesale electricity prices in the western United States during 2000 and 2001. Duke Energy has resolved these issues, which are described in detail below, through the California Settlement.
•
In FERC refund proceedings, the FERC ordered some sellers, including DETM, to refund, or to offset against outstanding accounts receivable, amounts billed for electricity sales in excess of a FERC-established proxy price. In 2002, the presiding administrative law judge in the FERC refund proceedings issued preliminary estimates that indicated DETM had refund liability of approximately $95 million. The FERC issued staff recommendations and an order in 2003 that modified the prior refund methodology by changing the gas proxy price used in the refund calculation. Platts, an energy industry publication, reported that a FERC spokesman announced that the methodology change could increase the total aggregate refund amount for all generators from $1.8 billion to at least $3.3 billion.
•
In 2003, the FERC issued an Order to Show Cause concerning “Enron-type gaming behavior,” and a companion order requiring suppliers, including DETM, to justify bids in the California Independent System Operator and the California Power Exchange markets made above the level of $250 per megawatt hour from May 1, 2000 through October 1, 2000. Later in 2003, the FERC Staff and Duke Energy announced two agreements to resolve all matters at issue in both of those orders. Duke Energy agreed to pay up to $4.59 million to benefit California and western electricity consumers, pending final approval by the FERC. The FERC approved the agreement involving bidding practices and rejected objections to the agreement. The objectors sought review of the FERC’s ruling on this agreement from the U.S. Ninth Circuit Court of Appeals. In April 2004, the administrative law judge reviewing the remaining agreement approved the settlement and rejected the objections. FERC approved the second agreement and made findings that set Duke Energy’s settlement amount with respect to both agreements at approximately $3 million, payment of which has been credited towards the California Settlement payment amount. The challenges to the two agreements are resolved through the California Settlement.
•
At the state level, the California Public Utilities Commission (CPUC), a California State Senate Select Committee, the California Attorney General (with participation by the Attorneys General of Washington and Oregon) and the San Diego District Attorney have conducted formal and informal investigations involving Duke Capital subsidiaries regarding the California energy markets, including review of alleged manipulation of energy prices. In addition, the U.S. Attorney’s Office in San Francisco served a grand jury subpoena on Duke Energy in 2002 seeking information relating to possible manipulation of the California electricity markets, including potential antitrust violations. All investigations (the State Civil Investigations), other than criminal investigations are resolved through the California Settlement. Duke Capital does not believe the outcome of any remaining criminal investigation will have a material adverse effect on its consolidated results of operations, cash flows or financial position.
In July 2004, Duke Energy reached an agreement in principle with the FERC, the State of California and other in- and out-of-state participants to settle the FERC refund proceedings and other significant litigation related to the western energy markets during 2000-2001 described above. The class action portion of the settlement is subject to court approval, but FERC approved all remaining provisions of the settlement in December 2004. As part of the agreement, Duke Capital agreed to provide approximately $208 million in cash
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
and credits to various parties involved in the settlement. The parties agreed to forgo all claims relating to refunds or other monetary damages for sales of electricity during the settlement period (January 1, 2000 through June 20, 2001), and claims alleging Duke Capital subsidiaries received unjust or unreasonable rates for the sale of electricity during the settlement period. The settlement resolved, among other matters:
•
All western refund proceedings pending before the FERC
•
The State Civil Investigations
•
The Western Power Class Action
•
Natural gas price issues raised by the California attorney general, PG&E, SCE and San Diego Gas & Electric Company
Duke Capital recorded an approximate $105 million pre-tax charge in the second quarter of 2004 at DENA to reflect the settlement agreement. This charge was recorded in Operation, Maintenance and Other on the Consolidated Statements of Operations. In December 2004, Duke Capital caused to be tendered all of the settlement proceeds except for $7 million relating to the class-action settlement. This remaining amount, which is fully reserved, will be paid upon court approval of the class-action settlement.
In Lockyer v. FERC, the U.S. Ninth Circuit Court of Appeals ruled in September 2004 that while FERC’s authorization of market based rate tariffs complied with the Federal Power Act, the failure by sellers of electricity to file appropriate quarterly reports provides the FERC with authority to award refunds relating to the period prior to October 2000. The court declined to order refunds requested by the State of California but remanded the case to the FERC for further proceedings consistent with its opinion. The California Settlement resolves refund issues relating to the post-October 2000 refund period as well as the pre-October 2000 period that was at issue in the Lockyer case. While the Lockyer ruling does not affect Duke Energy’s settlement, the decision could give rise to potential refund liability at the FERC for market-based rate sellers generally, including Duke Capital affiliates, to the extent quarterly reports filed by those entities are incomplete or inaccurate.
Trading Related Litigation. Beginning in 2002, 17 shareholder class-action lawsuits were filed against Duke Energy: 13 in the U.S. District Court for the Southern District of New York and four in the U.S. District Court for the Western District of North Carolina. These lawsuits arose out of allegations that Duke Capital subsidiaries improperly engaged in “round trip” trades which resulted in an alleged overstatement of revenues over a three-year period. By late 2003, the two federal courts had dismissed all 17 lawsuits. Plaintiffs in the New York cases appealed the dismissal order to the U.S. Second Circuit Court of Appeals. On November 15, 2004, appellate court affirmed the trial court’s dismissal of the New York cases
Commencing August 2003, plaintiffs filed three class-action lawsuits in the U.S. District Court for the Southern District of New York on behalf of entities who bought and sold natural gas futures and options contracts on the NYMEX during the years 2000 through 2002. DETM, along with numerous other entities, is named as a defendant. The cases claim that the defendants violated the Commodity Exchange Act by reporting false and misleading trading information to trade publications, resulting in monetary losses to the plaintiffs. Plaintiffs seek class action certification, unspecified damages and other relief. On September 24, 2004, the court denied a motion to dismiss the plaintiffs’ claims filed on behalf of DETM and other defendants. On January 25, 2005, the plaintiffs filed a motion for class certification; defendants are opposing the motion which has not yet been scheduled for hearing. Duke Capital is unable to express an opinion regarding the probable outcome of these matters at this time.
On January 28, 2005, four plaintiffs filed suit in Tennessee Chancery Court against Duke Capital subsidiaries and other energy companies seeking class action certification on behalf of indirect purchasers of
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
natural gas who allege that they have been harmed by defendants’ manipulation of the natural gas markets by various means, including providing false information to natural gas trade publications and unlawfully exchanging information, resulting in artificially high natural gas prices paid by plaintiffs in the State of Tennessee. Alleging that defendants violated state antitrust laws and other laws, plaintiffs seek unspecified damages and other relief. Duke Capital is unable to express an opinion regarding the probable outcome of these matters at this time.
Trading Related Investigations. In 2002 and 2003, Duke Energy responded to information requests and subpoenas from the SEC and to grand jury subpoenas issued by the U.S. Attorney’s office in Houston, Texas. The information requests and subpoenas sought documents and information related to trading activities by Duke Capital subsidiaries, including so-called “round-trip” trading. Duke Energy received notice in 2002 that the SEC formalized its trading-related investigation and is cooperating with the SEC. Based on discussions with the SEC staff in March 2005, Duke Energy anticipates making an offer of settlement to resolve the issues that are the subject of the SEC’s investigation regarding conduct that occurred in 2000 through June 2002. The terms of the anticipated offer would include issuance of an order to Duke Energy and its subsidiaries to cease and desist from violating internal controls and books and records requirements under Sections 13(b)(2)(A) and 13(b)(2)(B) of the Securities Exchange Act of 1934, but would not include a penalty or finding of fraud. Duke Capital has taken actions to remediate the issues that have been raised in the SEC’s investigation regarding internal controls. Any offer of settlement Duke Energy makes would be subject to approval by the SEC.
In April 2004, the Houston-based federal grand jury issued indictments for three former employees of DETMI Management Inc. (DETMI), which is one of two members of DETM. The indictments state that the employees “did knowingly devise, intend to devise, and participate in a scheme to defraud and to obtain money and property from Duke Energy by means of materially false and fraudulent pretenses, representations and promises, and material omissions, and to deprive Duke Energy and its shareholders of the intangible right to the honest services of employees of Duke Energy.” They further state that the alleged conduct was purportedly motivated, in part, by a desire to increase individual bonuses. Statements made by the U.S. Attorney’s office characterized Duke Energy as a victim in this activity and commended Duke Energy for its cooperation with the investigation. The alleged conduct was identified in the spring and summer of 2002 and was related to DETM’s Eastern Region trading activities. In 2002, Duke Capital recorded the appropriate financial adjustments associated with the cited activities, and did not consider the financial effect to be material. In February 2005, one of the 3 indicted former DETMI employees pled guilty to a books and records violation, and a superseding indictment was filed against the other two former employees, providing more detail and adding an allegation that the former employees intentionally circumvented internal accounting controls.
In February 2004, Duke Energy received a request for information from the U.S. Attorney’s office in Houston focused on the natural gas price reporting activity of a former DETM trader. Duke Energy has cooperated with the government in this investigation and Duke Capital is unable to express an opinion regarding the probable outcome at this time.
In February 2005, the Commodity Futures Trading Commission initiated a civil action against a former DETM trader asserting charges of delivering false reports and attempted manipulation of prices through index price reporting. Duke Capital is not named in this action.
Sonatrach/Sonatrading Arbitration. Duke Energy LNG Sales Inc. (Duke LNG), a Duke Capital subsidiary, claims in an arbitration commenced in January 2001 in London that Sonatrach, the Algerian state-owned energy company, together with its subsidiary, Sonatrading Amsterdam B.V. (Sonatrading), breached their shipping obligations under a liquefied natural gas (LNG) purchase agreement and related transportation agreements (the LNG Agreements) relating to Duke LNG’s purchase of LNG from Algeria and its transportation
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
by LNG tanker to Lake Charles, Louisiana. Duke LNG seeks damages of approximately $27 million. Sonatrading and Sonatrach claim that Duke LNG repudiated the LNG Agreements by allegedly failing to diligently perform LNG marketing obligations. Sonatrading and Sonatrach seek damages in the amount of approximately $600 million. In 2003, an arbitration panel issued a Partial Award on liability issues, finding that Sonatrach and Sonatrading breached their obligations to provide shipping. The panel also found that Duke LNG breached the LNG Purchase Agreement by failing to perform marketing obligations. The hearing on damages issues is scheduled to commence in September 2005.
Citrus Trading Corporation (Citrus) Litigation. In conjunction with the Sonatrach LNG Agreements, Duke LNG entered into a natural gas purchase contract (the Citrus Agreement) with Citrus. Citrus filed a lawsuit in March 2003 in the U.S. District Court for the Southern District of Texas against Duke LNG and PanEnergy Corp alleging that Duke LNG breached the Citrus Agreement by failing to provide sufficient volumes of gas to Citrus. Duke LNG contends that Sonatrach caused Duke LNG to experience a loss of LNG supply that affected Duke LNG’s obligations and termination rights under the Citrus Agreement. Citrus seeks monetary damages and a judicial determination that Duke LNG did not experience such a loss. After Citrus filed its lawsuit, Duke LNG terminated the Citrus Agreement and filed a counterclaim asserting that Citrus had breached the agreement by, among other things, failing to provide sufficient security under a letter of credit for the gas transactions. Citrus denies that Duke LNG had the right to terminate the agreement and contends that Duke LNG’s termination of the agreement was itself a breach, entitling Citrus to terminate the agreement and recover damages in the amount of approximately $187 million. Cross motions for partial summary judgment regarding the letter of credit issue have been filed and are pending. No trial date has been set. It is not possible to predict with certainty whether Duke Capital will incur any liability or to estimate the damages, if any, that Duke Capital might incur in connection with the Sonatrach and Citrus matters.
ExxonMobil Disputes. In April 2004, Mobil Natural Gas, Inc. (MNGI) and 3946231 Canada, Inc. (3946231, and collectively with MNGI, ExxonMobil) filed a Demand for Arbitration against Duke Energy and DETMI, DTMSI Management Ltd. (DTMSI) and other subsidiaries of Duke Capital. MNGI and DETMI are the sole members of DETM. DTMSI and 3946231 are the sole beneficial owners of Duke Energy Marketing Limited Partnership (DEMLP, and with DETM, the Ventures). Among other allegations, ExxonMobil alleges that DETMI and DTMSI engaged in wrongful actions relating to affiliate trading, payment of service fees, expense allocations and distribution of earnings in breach of agreements and fiduciary duties relating to the Ventures. ExxonMobil seeks to recover actual damages, plus attorneys’ fees and exemplary damages; aggregate damages were not specified in the arbitration demand. Duke Energy denies these allegations, and has filed counterclaims asserting that ExxonMobil breached its Ventures obligations and other contractual obligations. A hearing in this arbitration has been tentatively scheduled for January 2006. In August 2004, DEMLP initiated arbitration proceedings in Canada against certain ExxonMobil entities asserting that those entities wrongfully terminated two gas supply agreements with the Ventures and wrongfully failed to assume certain related gas supply agreement with other parties. A hearing in the Canadian arbitration proceeding has been scheduled to begin in August 2005. These matters are in very early stages, and it is not possible to predict with certainty the damages that might be incurred by Duke Capital or any of its affiliates as a result of these matters.
Other Litigation and Legal Proceedings. Duke Capital and its subsidiaries are involved in other legal, tax and regulatory proceedings in various forums regarding performance, contracts, royalty disputes, mismeasurement and mispayment claims (some of which are brought as class actions), and other matters arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will have no material adverse effect on consolidated results of operations, cash flows or financial position.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Duke Capital has exposure to certain legal matters that are described herein. As of December 31, 2004, Duke Capital has recorded reserves of approximately $154 million for these proceedings and exposures. These reserves represent management’s best estimate of probable loss as defined by SFAS No. 5, “Accounting for Contingencies.”
Duke Capital expenses legal costs related to the defense of loss contingencies as incurred.
Other Commitments and Contingencies
As part of its normal business, Duke Capital is a party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Duke Capital having to honor its contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. Duke Capital would record a reserve if events occurred that required that one be established. (For further information see Note 17.)
In addition, Duke Capital enters into various fixed-price, non-cancelable commitments to purchase or sell power (tolling arrangements or power purchase contracts), take-or-pay arrangements, transportation or throughput agreements and other contracts that may or may not be recognized on the Consolidated Balance Sheets. Some of these arrangements may be recognized at market value on the Consolidated Balance Sheets as trading contracts or qualifying hedge positions included in Unrealized Gains or Losses on Mark-to-Market and Hedging Transactions.
Operating and Capital Lease Commitments
Duke Capital leases assets in several areas of its operations. Consolidated rental expense for operating leases was $79 million in 2004, $81 million in 2003 and $70 million in 2002, and included in Operation, Maintenance and Other on the Consolidated Statements of Operations. Amortization of assets recorded under capital leases was included in Depreciation and Amortization on the Consolidated Statements of Operations. The following is a summary of future minimum lease payments under operating leases, which at inception had a noncancelable term of more than one year, and capital leases as of December 31, 2004:
17. Guarantees and Indemnifications
Duke Capital and its subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. Duke Capital enters
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party.
Mixed Oxide (MOX) Guarantees. DCS is the prime contractor to the DOE under a contract (the Prime Contract) pursuant to which DCS will design, construct, operate and deactivate a domestic MOX fuel fabrication facility (the MOX FFF) and provide for the irradiation of the MOX fuel. The domestic MOX fuel project was prompted by an agreement between the United States and the Russian Federation to dispose of excess plutonium in their respective nuclear weapons programs by fabricating MOX fuel and irradiating such MOX fuel in commercial nuclear reactors. As of December 31, 2004, Duke Capital, through its indirect wholly owned subsidiary, Duke Project Services Group Inc. (DPSG), held a 40% ownership interest in DCS.
The Prime Contract consists of a “Base Contract” phase and successive option phases. The DOE has the right to extend the term of the Prime Contract to cover the option phases on a sequential basis, subject to DCS and the DOE reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. As of December 31, 2004, DCS’ performance obligations under the Prime Contract included only the Base Contract phase and the first option phase covering mission reactor modifications.
DPSG and the other owners of DCS have issued a guarantee to the DOE which, in conjunction with the applicable guarantee provisions (as clarified by an April 2004 amendment) in the Prime Contract (collectively, the DOE Guarantee), obligates the owners of DCS to jointly and severally guarantee to the DOE that the owners of DCS will reimburse the DOE (in the event that DCS fails to provide such reimbursement) for any payments made by the DOE to DCS pursuant to the Prime Contract that DCS expends on costs that are not “allowable” under certain applicable federal acquisition regulations. DPSG has recourse to the other owners of DCS for any amounts paid under the DOE Guarantee in excess of its proportional ownership percentage of DCS. Although the DOE Guarantee does not provide for a specific limitation on a guarantor’s reimbursement obligations, Duke Capital estimates that the maximum potential amount of future payments DPSG could be required to make under the DOE Guarantee is immaterial. As of December 31, 2004, Duke Capital had no liabilities recorded on its Consolidated Balance Sheets for the DOE Guarantee due to the immaterial amount of the estimated fair value of such guarantee.
In connection with the Prime Contract, Duke Energy, through its Duke Power franchised electric business, has entered into a subcontract with DCS (the Duke Power Subcontract) pursuant to which Duke Power will prepare its McGuire and Catawba nuclear reactors (the Mission Reactors) for use of the MOX fuel, and which also includes terms and conditions applicable to Duke Power’s purchase of MOX fuel produced at the MOX FFF for use in the Mission Reactors. The Duke Power Subcontract consists of a “Base Subcontract” phase and successive option phases. DCS has the right to extend the term of the Duke Power Subcontract to cover the option phases on a sequential basis, subject to Duke Power and DCS reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. As of December 31, 2004, DCS’ performance obligations under the Duke Power Subcontract included only the Base Subcontract phase and the first option phase covering mission reactor modifications.
DPSG and the other owners of DCS have issued a guarantee to Duke Power (the Duke Power Guarantee) pursuant to which the owners of DCS jointly and severally guarantee to Duke Power all of DCS’ obligations under the Duke Power Subcontract or any other agreement between DCS and Duke Power implementing the Prime Contract. DPSG has recourse to the other owners of DCS for any amounts paid under the Duke Power Guarantee in excess of its proportional ownership percentage of DCS. Even though the Duke Power Guarantee does not provide for a specific limitation on a guarantor’s guarantee obligations, it does provide that any liability of such guarantor under the Duke Power Guarantee is directly related to and limited by the terms and conditions
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
in the Duke Power Subcontract and any other agreements between Duke Power and DCS implementing the Duke Power Subcontract. Duke Capital is unable to estimate the maximum potential amount of future payments DPSG could be required to make under the Duke Power Guarantee due to the uncertainty of whether:
•
DCS will exercise its options under the Duke Power Subcontract, which will depend upon whether the DOE will exercise its options under the Prime Contract, which, in turn, will depend on whether the U.S. Congress will authorize funding for DCS’s work under the Prime Contract, and
•
the parties to the Prime Contract and the Duke Power Subcontract, respectively, will reach agreement on the remaining open terms for each option phase under the contracts, and if so, what the terms and conditions might be.
Duke Capital has not recorded on its Consolidated Balance Sheets any liability for the potential exposure under the Duke Power Guarantee per FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” because DPSG and Duke Power are under common control.
Other Guarantees and Indemnifications. Duke Capital has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly owned entities. The maximum potential amount of future payments Duke Capital could have been required to make under these performance guarantees as of December 31, 2004 was approximately $2.4 billion. Of this amount, approximately $1.3 billion relates to guarantees of payments and performance of affiliated entities such as Duke Energy Merchants, LLC (DEM) and approximately $660 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $200 million of the performance guarantees expire between 2005 and 2007, with the remaining performance guarantees expiring after 2008 or having no contractual expiration. Additionally, Duke Capital has issued joint and several guarantees to some of the D/FD project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments. These guarantees have no contractual expiration and no stated maximum amount of future payments that Duke Capital could be required to make. Additionally, Fluor Enterprises Inc., as 50% owner in D/FD, has issued similar joint and several guarantees to the same D/FD project owners. In accordance with the D/FD partnership agreement, each of the partners is responsible for 50% of any payments to be made under those guarantees.
Westcoast has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method projects, and of entities previously sold by Westcoast to third parties. Those guarantees require Westcoast to make payment to the guaranteed third party upon the failure of an unconsolidated entity to make payment under some of its contractual obligations, such as debt, purchase contracts and leases. The maximum potential amount of future payments Westcoast could have been required to make under those performance guarantees as of December 31, 2004 was approximately $60 million. Of those guarantees, approximately $10 million expire in 2006, with the remainder having no contractual expiration.
Duke Capital uses bank-issued stand-by letters of credit to secure the performance of non-wholly owned entities to a third party or customer. Under these arrangements, Duke Capital has payment obligations to the issuing bank which are triggered by a draw by the third party or customer due to the failure of the non-wholly owned entity to perform according to the terms of its underlying contract. The maximum potential amount of future payments Duke Capital could have been required to make under these letters of credit as of December 31, 2004 was approximately $400 million. Of this amount, approximately $350 million relates to letters of credit issued on behalf of less than wholly owned consolidated entities and approximately $5 million relates to affiliated entities such as DEM. Substantially all of these letters of credit expire in 2005.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Duke Capital has guaranteed certain issuers of surety bonds, obligating itself to make payment upon the failure of a non-wholly owned entity to honor its obligations to a third party. As of December 31, 2004, Duke Capital had guaranteed approximately $95 million of outstanding surety bonds related to obligations of non-wholly owned entities. The majority of these bonds expire in various amounts between 2005 and 2006. Of this amount, approximately $15 million relates to affiliated entities such as DEM and approximately $10 million relates to obligations of less than wholly owned consolidated entities.
Natural Gas Transmission and International Energy have issued guarantees of debt and performance guarantees associated with non-consolidated entities and less than wholly-owned entities. If such entities were to default on payments or performance, Natural Gas Transmission or International Energy would be required under the guarantees to make payment on the obligation of the less than wholly-owned entity. As of December 31, 2004, Natural Gas Transmission was the guarantor of approximately $15 million of debt at Westcoast associated with less than wholly owned entities, with approximately $8 million expiring in 2009 and the remainder having no contractual expiration. International Energy was the guarantor of approximately $70 million of performance guarantees associated with less than wholly-owned entities, with substantially all of the guarantees expiring in 2005.
Duke Capital has issued guarantees to customers or other third parties related to the payment or performance obligations of certain entities that were previously wholly owned by Duke Capital but which have been sold to third parties, such as DukeSolutions and DE&S. These guarantees are primarily related to payment of lease obligations, debt obligations, and performance guarantees related to goods and services provided. Duke Capital has received back-to-back indemnification from the buyer of DE&S indemnifying Duke Capital for any amounts paid by Duke Capital related to the DE&S guarantees. Duke Capital also received indemnification from the buyer of DukeSolutions for the first $2.5 million paid by Duke Capital related to the DukeSolutions guarantees. Further, Duke Capital granted indemnification to the buyer of Duke Solutions with respect to losses arising under some energy services agreements retained by DukeSolutions after the sale, provided that the buyer agreed to bear 100% of the performance risk and 50% of any other risk up to an aggregate maximum of $2.5 million (less any amounts paid by the buyer under the indemnity discussed above). Additionally, for certain performance guarantees, Duke Capital has recourse to subcontractors involved in providing services to a customer. These guarantees have various terms ranging from 2004 to 2019, with others having no specific term. Duke Capital is unable to estimate the total maximum potential amount of future payments under these guarantees, since some of the underlying agreements have no limits on potential liability.
Additionally, in August 2004, Duke Capital guaranteed in favor of a bank the repayment of any draws under a $120 million letter of credit issued by such bank to Georgia Power Company, which expires in 2005, related to the obligation of a KGen subsidiary under a seven year power sales agreement, commencing in May 2005, as discussed in Note 2. Duke Capital will be required to ensure reissuance of this letter of credit or issue similar credit support until the power sales agreement expires in 2012. Duke Energy will operate the Murray facility under an operation and maintenance agreement with the KGen subsidiary. As a result, the guarantee has an immaterial fair value. Further, KGen has agreed to indemnify Duke Capital for any payments made by Duke Capital with respect to the $120 million letter of credit.
Duke Capital has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Capital’s maximum potential exposure under these indemnification agreements can range from a specified to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Duke Capital
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
is unable to estimate the total maximum potential amount of future payments under these indemnification agreements due to several factors, including uncertainty as to whether claims will be made.
As of December 31, 2004, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.
18. Stock-Based Compensation
Certain employees of Duke Capital participate in Duke Energy’s stock compensation plans, including options, restricted stock awards, performance awards and phantom stock awards. Duke Energy’s 1998 Long-term Incentive Plan, as amended (the 1998 Plan), reserved 60 million shares of common stock for awards to employees and outside directors. Under the 1998 Plan, the exercise price of each option granted cannot be less than the market price of Duke Energy’s common stock on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to five years.
Upon the acquisition of Westcoast, Duke Energy converted all stock options outstanding under the 1989 Westcoast Long-term Incentive Share Option Plan to Duke Energy stock options. Certain of these options also provide for share appreciation rights under which the holder of a stock option may, in lieu of exercising the option, exercise the share appreciation right. The exercise price of these options equals the market price on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to four years.
The following tables show information regarding options to purchase Duke Energy’s common stock granted to employees of Duke Capital.
Stock Option Activity
(a)
Includes 2,746 converted Westcoast stock options
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Stock Options at December 31, 2004
As of December 31, 2003, Duke Energy had 15.9 million exercisable options with a $32 weighted-average exercise price. As of December 31, 2002, Duke Energy had 16.0 million exercisable options with a $32 weighted-average exercise price.
There were no options granted in 2004. The weighted-average fair value per option granted was $4 for 2003 and $10 for 2002. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model.
Weighted-Average Assumptions for Option-Pricing
The 1998 Plan allows for a maximum of 12 million shares of common stock to be issued in the form of restricted stock awards, performance awards and phantom stock awards. Stock-based performance awards granted under the 1998 Plan vest over periods from three to seven years. Vesting can occur in three years, at the earliest if performance is met. Duke Energy awarded 1,442,140 shares (fair value of approximately $31 million at grant dates) in 2004, 75,000 shares (fair value of approximately $2 million at grant dates) in 2003 and 16,000 shares (fair value of approximately $1 million at grant dates) in 2002. Compensation expense for the performance awards is charged to earnings over the vesting period and totaled $8 million in 2004, $2 million in 2003 and $3 million in 2002.
Phantom stock awards granted under the 1998 Plan vest over periods ranging from one to five years. Duke Energy awarded 1,169,090 shares (fair value of approximately $25 million at grant dates) in 2004, 285,000 shares (fair value of approximately $5 million at grant dates) in 2003 and 54,430 shares (fair value of approximately $2 million at grant dates) in 2002. Compensation expense for the phantom awards is charged to earnings over the vesting period and totaled $11 million in 2004, $6 million in 2003 and $9 million in 2002.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Restricted stock awards granted under the 1998 Plan vest over periods ranging from one to five years. Duke Energy awarded 169,160 shares (fair value of approximately $4 million at grant dates) in 2004, 19,897 shares (fair value of less than $1 million at grant dates) in 2003 and 10,260 shares (fair value of less than $1 million at grant dates) in 2002. Compensation expense for restricted awards is charged to earnings over the vesting period and totaled less than $1 million in 2004, $1 million in 2003 and $1 million in 2002.
Duke Energy’s 1996 Stock Incentive Plan (the 1996 Plan) allowed four million shares of common stock for awards to employees. As of December 31, 2004, there are no more awards outstanding under the 1996 Plan. Duke Energy awarded no restricted shares in 2004, 2003 and 2002. Compensation expense for restricted awards is charged to earnings over the vesting period and totaled less than $1 million in 2004 and 2003 and $1 million in 2002. The 1996 Plan is not available for new awards.
19. Employee Benefit Plans
U.S. Retirement Plan. Duke Capital and its subsidiaries participate in Duke Energy’s non-contributory defined benefit retirement plan. The plan covers most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits.
Duke Energy’s policy is to fund amounts on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants. Duke Energy made a voluntary contribution of $250 million to its defined benefit retirement plan in 2004 and $181 million in 2003. No contribution to the Duke Energy plan was made in 2002. Duke Energy does not anticipate making a contribution to the plan in 2005.
The net unrecognized transition asset, resulting from the implementation of accrual accounting, is amortized over approximately 20 years. Duke Energy determines the market-related value of plan assets using a calculated value that recognizes changes in fair value of the plan assets over five years. Duke Energy uses a September 30 measurement date for its defined benefit retirement plan.
The fair value of Duke Energy’s plan assets was $2,477 million as of September 30, 2004 and $2,477 million as of September 30, 2003. The projected benefit obligation was $2,693 million as of September 30, 2004 and $2,763 million as of September 30, 2003.
Duke Capital’s net periodic pension benefit, including amounts allocated by Duke Energy, was $28 million for 2004, $25 million for 2003 and $37 million for 2002.
Assumptions Used for Duke Energy’s U.S. Pension Benefits Accounting
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Duke Energy also sponsors, and Duke Capital participates in an employee savings plan that covers substantially all U.S. employees. Duke Energy contributes a matching contribution equal to 100% of before-tax employee contributions, of up to 6% of eligible pay per period. Duke Capital expensed plan contributions, including amounts allocated by Duke Energy, of $20 million in 2004, $24 million in 2003 and $30 million in 2002.
Duke Energy also maintains, and Duke Capital participates in, a non-qualified, non-contributory defined benefit retirement plan which covers certain U.S. executives. There are no plan assets. The Duke Energy projected benefit obligation was $86 million as of September 30, 2004 and $101 million as of September 30, 2003. Duke Capital expensed amounts allocated by Duke Energy of $5 million in 2004, $6 million in 2003, and $5 million in 2002.
Westcoast Canadian Retirement Plans. Westcoast and its subsidiaries maintain contributory and non-contributory defined benefit (DB) and defined contribution (DC) retirement plans covering substantially all employees. The DB plans provide retirement benefits based on each plan participant’s years of service and final average earnings. Under the DC plans, company contributions are determined according to the terms of the plan and based on each plan participant’s age, years of service and current eligible earnings.
Westcoast’s policy is to fund the DB plans on an actuarial basis and in accordance with Canadian pension standards legislation, in order to accumulate assets sufficient to meet benefits to be paid. Contributions to the DC plans are determined in accordance with the terms of the plan. Duke Energy made contributions to the Westcoast DB plans of approximately $28 million in 2004, $11 million in 2003, and $9 million in 2002. Duke Energy anticipates that it will make contributions of approximately $33 million to the Westcoast DB plans in 2005. Duke Energy also made contributions to the DC plans of $3 million in 2004, $3 million in 2003, and $2 million in 2002. Duke Energy anticipates that it will make contributions to the DC plans of approximately $3 million in 2005.
The net unrecognized transition asset and actuarial gains and losses are amortized over the average remaining service period of the active employees. The average remaining service period of the active employees covered by the DB retirement plans is 13 years. Westcoast uses a September 30 measurement date for its plans.
Components of Net Periodic Pension Costs for Westcoast-for the years ended December 31,
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Reconciliation of Funded Status to Net Amount Recognized for Westcoast-as of December 31,
For Westcoast, the accumulated benefit obligation was $435 million at September 30, 2004 and $394 million at September 30, 2003.
Amounts Recognized in the Consolidated Balance Sheets for Westcoast Consist of:-as of December 31,
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Additional Information for Westcoast:
Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets for Westcoast
Assumptions Used for Pension Benefits Accounting for Westcoast
For Westcoast the discount rate used to determine the pension obligation is prescribed as the yield on Canadian corporate AA bonds at the measurement date of September 30. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan.
Plan Assets Westcoast:
(a)
EAFE-Europe, Australasia, Far East
Westcoast assets for registered pension plans are maintained by a Master Trust. The investment objective of the Master Trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation targets were set after considering the investment objective and the risk profile with respect to the trust. Canadian equities are held for their high expected return. Non-Canadian equities are held for their high expected return as well as diversification relative to Canadian equities and debt securities. Debt securities are held for diversification. Under
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
the Income Tax Act (Canada), pension funds are only permitted to invest 30% of the book value of assets in foreign investments.
The long-term rate of return of 7.5% as of September 30, 2004 for the Westcoast assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes were 2.0% for Canadian equities, 1.9% for U.S. equities, 1.9% for Europe, Australasia and Far East equities, and 1.7% for fixed income securities.
Westcoast also provides non-registered defined benefit supplemental pensions to all employees who retire under a defined benefit registered pension plan and whose pension is limited by the maximum pension limits under the Income Tax Act (Canada). Westcoast recognized net periodic pension expense of $4 million in 2004, $4 million in 2003, and $3 million in 2002. There are no plan assets. The projected benefit obligation was $66 million as of September 30, 2004 and $60 million as of September 30, 2003.
Duke Energy U.S. Other Post-Retirement Benefits. Duke Capital and most of its subsidiaries, in conjunction with Duke Energy provide some health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.
These benefit costs are accrued over an employee’s active service period to the date of full benefits eligibility. The net unrecognized transition obligation, resulting from accrual accounting, is amortized over approximately 20 years. Duke Energy uses a September 30 measurement date for its other post-retirement benefit plans.
The fair value of Duke Energy’s plan assets was $243 million as of September 30, 2004 and $242 million as of September 30, 2003. The accumulated post-retirement benefit obligation was $782 million as of September 30, 2004 and $924 million as of September 30, 2003.
Duke Capital’s net periodic post-retirement benefit cost, as allocated by Duke Energy, was $19 million for 2004 and $24 million in 2003.
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Assumptions Used in Duke Energy’s U.S. Other Post-Retirement Benefits Accounting
For measurement purposes, the net per capita cost of covered health care benefits for employees who are not eligible for Medicare is assumed to have an initial annual rate of increase of 9.5% in 2004 that will gradually decrease to 6% in 2009. For employees who are eligible for Medicare, an initial annual rate of increase of 12.5% in 2004 will gradually decrease to 6% in 2012. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% increase or decrease in the assumed health care trend rate would change the allocated net periodic post-retirement benefit cost for Duke Capital to increase or decrease by approximately $1 million.
Westcoast Canadian Other Post-Retirement Benefits. Westcoast provides health care and life insurance benefits for retired employees on a non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans. Effective December 31, 2003, a new plan was implemented for all non bargaining employees and the majority of bargaining employees. The new plan will apply for employees retiring on and after January 1, 2006. The new plan is predominantly a defined contribution plan as compared to the existing defined benefit program.
Other post-retirement benefit costs are accrued over an employee’s active service period to the date of full benefits eligibility. The net unrecognized transition obligation, resulting from accrual accounting, is amortized over the average remaining service period of the active employees covered by the plans. The average remaining service period of the active employees is 18 years. Westcoast uses a September 30th measurement date for its plans.
Components of Net Periodic Post-Retirement Benefit Costs for Westcoast-for the years ended December 31,
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Assumptions Used for Post-Retirement Benefits Accounting for Westcoast
For Westcoast the discount rate used to determine the pension obligation is prescribed as the yield on Canadian corporate AA bonds at the measurement date of September 30. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan.
Assumed Health Care Cost Trend Rates for Westcoast
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
Sensitivity to Changes in Assumed Health Care Cost Trend Rates Westcoast Plans
Westcoast expects to make the future benefit payments, which reflect expected future service, as appropriate. The following benefit payments are expected to be paid over each of the next five years and thereafter.
Expected Benefit Payments
20. Quarterly Financial Data (Unaudited)
The amounts in the above tables have been adjusted from previously reported amounts due to operations that were classified as discontinued operations as of the fourth quarter of 2004 (see Note 12). During the first quarter of 2004, Duke Capital recorded the following unusual or infrequently occurring items: a $256 million pre-tax gain on sale of International Energy’s Asia-Pacific Business (see Note 12); and an approximate $360 million pre-tax charge in 2004 associated with the sale of DENA’s Southeast Plants (see Note 2).
During the second quarter of 2004, Duke Capital recorded the following unusual or infrequently occurring items: a $109 million (net of minority interest of $5 million) pre-tax gain related to the settlement of the Enron bankruptcy proceedings; a $39 million net increase in the pre-tax gains ($30 million increase to the after tax gains) originally recorded on the sales of International Energy’s Asia-Pacific Business (see Note 12) and its
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
European Business; a $52 million release of various income tax reserves (see Note 5); and a $105 million pre-tax charge related to the California and Western U.S. energy markets settlement (see Note 16).
During the third quarter of 2004, Duke Capital recorded the following unusual or infrequently occurring items: a $48 million tax benefit related to the realignment of certain subsidiaries of Duke Capital and the pass-through structure of these for U.S. income tax purposes (see Note 5); a $1,030 million one time tax expense in 2004 related to the realignment of certain subsidiaries of Duke Capital and the pass-through structure of these for U.S. income tax purposes; and impairments of $45 million (net of minority interest of $26 million) related to asset impairments, losses on asset sales and write-down of equity investments at Field Services (See Note 11).
During the fourth quarter of 2004, Duke Capital recorded the following unusual or infrequently occurring items: a $180 million of pre-tax gains associated with the sales of two DENA partially completed facilities, Luna and Moapa (See Note 2); a $59 million pre-tax correction of accounting errors related to captive insurance reserves at Bison (see Note 1); a $28 million pre-tax charge at Bison for reinsurance policies which have certain retrospective rating provisions, ($12 million of which relates to the correction of an accounting error related to prior years) (see Note 1); a $51 million pre-tax charge related to the sale of DETM contracts that were held in a net liability position; $20 million in contract termination charges related to the DENA partially completed plant at Grays Harbor; and approximately $42 million of impairment charges related to two Crescent residential developments in Payson, Arizona and one in Austin, Texas (See Note 11); and $8 million in bad debt charges recorded by Crescent related to notes receivable due from Rim Golf Investor LLC and Chaparral Pines Investor LLC. The bad debt charges are recorded to Operation, Maintenance and Other on the Consolidated Statement of Operations (See Note 11).
During the second quarter of 2003, Duke Capital recorded a $178 million pre-tax gain from the sale of DENA’s 50% interest in Ref-Fuel. (See Note 2).
During the third quarter of 2003, Duke Capital recorded the following unusual or infrequently occurring items: goodwill impairment related to DENA’s trading and marketing business of $254 million (see Note 9), severance charges of $105 million for workforce reductions; a $52 million tax benefit related to International Energy’s goodwill impairment recognized in 2002 for the gas trading business in Europe; and a settlement with the Commodity Futures Trading Commission of $17 million, net of minority interest expense, by DENA.
During the fourth quarter of 2003, Duke Capital recorded the following unusual or infrequently occurring items: impairments on DENA’s Southeast Plants and its deferred Western plants and charges for the re-designation of certain hedges at DENA from accrual to mark-to-market that were related to its impaired assets of $2,903 million (see Note 11); charges and impairments of $292 million to complete International Energy’s exit from the European market and the divestiture of its Asia-Pacific Business; a $51 million write-off of an abandoned corporate risk management information system; severance charges of $15 million for workforce reductions; additional employee benefit expense of approximately $28 million.
21. Subsequent Events
In February 2005, DEFS sold its wholly-owned subsidiary TEPPCO for approximately $1.1 billion and Duke Capital sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to EPCO, an unrelated third party.
Additionally, in February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to cause a Duke Capital subsidiary to transfer a 19.7% interest in DEFS to ConocoPhillips for
DUKE CAPITAL LLC
Notes To Consolidated Financial Statements - Continued
direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. The consideration is expected to consist of the current Canadian operations of DEFS, the transfer of certain Canadian assets from ConocoPhillips to Duke Capital and the transfer of certain U.S. Midstream assets, or cash, from ConocoPhillips to DEFS, and the payment of cash from ConocoPhillips to Duke Capital of at least $500 million. Upon completion of this transaction, DEFS will be owned 50% by Duke Capital and 50% by ConocoPhillips. As a result, Duke Capital expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction. This transaction, which is subject to customary U.S. and Canadian regulatory approvals, is expected to close in the latter half of 2005.
As a result, Duke Capital expects to deconsolidate its investment in DEFS, subsequent to the closing of the transfer of its 19.7% interest to ConocoPhillips. During the first quarter of 2005 Duke Capital has discontinued hedge accounting for certain 2005 and 2006 contracts held by Duke Capital related to Field Services’ commodity risk, which were previously accounted for as cash flow hedges. As a result of discontinuation of hedge accounting treatment, approximately $140 million of pretax deferred losses in AOCI related to these contracts have been reclassified into earnings by Duke Capital in the first quarter of 2005. On a prospective basis, these contracts will be accounted for under the MTM Model.
On March 1, 2005, notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. The bondholders were notified that these securities would be called on April 15, 2005, the earliest date at which these bonds can be redeemed.
On March 23, 2005, Duke Capital distributed $750 million to its parent, Duke Energy, to provide funding for the execution of Duke Energy’s accelerated share acquisition plan. The distribution was principally obtained from Duke Capital’s portion of the cash proceeds realized from the recent sale by DEFS of the general partner of TEPPCO Partners, L.P. and Duke Capital’s sale of its limited partner interests in TEPPCO Partners, L.P.
DUKE CAPITAL LLC
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(a)
Primarily consists of cash payments and reserve reversals.
(b)
Primarily consists of litigation, impairment and other reserves, included in Other Current Liabilities, or Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Duke Capital’s management, including its President and its Chief Financial Officer, have evaluated the effectiveness of Duke Capital’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) (Disclosure Controls Evaluation) and concluded that, as of the end of the period covered by this report, the disclosure controls and procedures are effective in ensuring that all material information required to be filed in this annual report has been made known to them in a timely fashion. The required information was effectively recorded, processed, summarized and reported within the time period necessary to prepare this annual report. Duke Capital’s disclosure controls and procedures are effective in ensuring that information required to be disclosed in Duke Capital’s reports under the Exchange Act are accumulated and communicated to management, including the President and the Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
Because of Duke Capital’s ongoing evaluation of internal controls over financial reporting, management continues to implement procedures and controls to enhance the reliability of Duke Capital’s internal control procedures including planned improvements in our financial closing and consolidation processes. However, there have been no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, Duke Capital’s internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
None.
PART III.
Item 14.
Item 14. Principal Accounting Fees and Services.
Duke Capital, LLC (Duke Capital)-Fees Paid to Independent Auditor
The following table presents fees for professional services rendered by Deloitte & Touche LLP, and the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, Deloitte) for Duke Energy that were charged to Duke Capital for 2004 and 2003:
(a)
Audit Fees are fees billed or expected to be billed by Deloitte for professional services for the audit of Duke Energy’s consolidated financial statements included in Duke Energy’s annual report on Form 10-K and review of financial statements included in Duke Energy’s quarterly reports on Form 10-Q, services that are normally provided by Deloitte in connection with statutory, regulatory or other required filings or engagements or any other service performed by Deloitte to comply with generally accepted auditing standards and include comfort and consent letters in connection with Securities and Exchange Commission filings and financing transactions.
(b)
Sarbanes-Oxley Fees are fees billed or expected to be billed by Deloitte for professional services related to the audit of Duke Energy’s internal controls under Sarbanes-Oxley Section 404 requirements.
(c)
Audit-Related Fees are fees billed by Deloitte for assurance and related services that are reasonably related to the performance of an audit or review of Duke Energy’s financial statements, including assistance with acquisitions and divestitures, internal control reviews, employee benefit plan audits and general assistance with the implementation of the Securities and Exchange Commission rules pursuant to the Sarbanes-Oxley Act.
(d)
Tax Fees are fees billed by Deloitte for tax return assistance and preparation, tax examination assistance, and professional services related to tax planning and tax strategy.
(e)
All Other Fees are fees billed by Deloitte for any services not included in the first three categories, primarily translation of audited financials into foreign languages, accounting training and conferences.
(f)
The Duke Capital 10-K filed in 2004 stated that Audit Fees for fiscal 2003 were $8.5 million. That number did not include $1.6 million of Audit Fees that had not been billed and were not anticipated at the time that the 2004 Duke Capital 10-K was filed.
To safeguard the continued independence of the independent auditor, the Audit Committee adopted a policy that prevents Duke Energy’s independent auditor from providing services to Duke Energy and its subsidiaries that are prohibited under Section 10A(g) of the Securities Exchange Act of 1934, as amended. This policy also provides that independent auditors are only permitted to provide services to Duke Energy and its subsidiaries that have been pre-approved by the Audit Committee. Pursuant to the policy, all audit services require advance approval by the Audit Committee. All other services by the independent auditor that fall within certain designated dollar thresholds, both per engagement as well as annual aggregate, have been pre-approved under the policy. Different dollar thresholds apply to the three categories of pre-approved services specified in the policy (Audit-Related services, Tax services and Other services). All services that exceed the dollar thresholds must be approved in advance by the Audit Committee. Pursuant to applicable provisions of the Securities Exchange Act
of 1934, as amended, the Audit Committee has delegated approval authority to the Chairman of the Audit Committee. The Chairman has presented all approval decisions to the full Audit Committee. All services performed by the independent auditor were approved by the Audit Committee pursuant to its pre-approval policy, and services comprising 1% of Tax Fees and 14% of Other Fees were approved pursuant to the de minimus exception to the rules and regulations of the Securities and Exchange Commission on pre-approval.
In 2004 after the Securities and Exchange Commission issued a statement clarifying what constitutes a contingent fee arrangement for tax services, Duke Energy and Deloitte amended four previously existing fee arrangements into non-refundable fixed fees. Duke Capital’s portion of such fees, $2.4 million, are included in the 2004 fees disclosed above and $2.4 million more will be due and paid in the first quarter of 2005.
PART IV.
Item 15.
Item 15. Exhibits and Financial Statement Schedule
(a) Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedule included in Part II of this annual report are as follows:
Consolidated Financial Statements
Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002
Consolidated Balance Sheets as of December 31, 2004 and 2003
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002
Consolidated Statements of Member’s/Common Stockholder’s Equity and Comprehensive Income (Loss) for the Years Ended December 31, 2004, 2003 and 2002
Notes to the Consolidated Financial Statements
Quarterly Financial Data (unaudited, included in Note 20 to the Consolidated Financial Statements)
Consolidated Financial Statement Schedule II-Valuation and Qualifying Accounts and Reserves for the Years Ended December 31, 2004, 2003 and 2002
Report of Independent Registered Public Accounting Firm
All other schedules are omitted because they are not required, or because the required information is included in the Consolidated Financial Statements or Notes.
(b) Exhibits-See Exhibits Index immediately following the signature page.
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 and in the capacities and on the date indicated.
(i)
Principal executive officer:
/s/ DAVID L. HAUSER
David L. Hauser
President
(ii)
Principal financial and accounting officer:
/s/ KEITH G. BUTLER
Keith G. Butler
Chief Financial Officer and Controller
(iii)
Directors:
/s/ DAVID L. HAUSER
David L. Hauser
/s/ FRED J. FOWLER
Fred J. Fowler
/s/ JIM W. MOGG
Jim W. Mogg
Date: March 30, 2005
EXHIBITS INDEX
Exhibits filed herewith are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated. Items constituting management contracts or compensatory plans or arrangements are designated by a double asterisk (**).
The total amount of securities of the registrant or its subsidiaries authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to it.