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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
FOR ANNUAL AND TRANSITION REPORTS
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
| (Mark | One) |
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006 or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-33007
SPECTRA ENERGY CORP
(Exact name of registrant as specified in its charter)
Delaware | 20-5413139 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
5400 Westheimer Court, Houston, Texas | 77056 | |
(Address of principal executive offices) | (Zip Code) | |
713-627-5400
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class | Name of Each Exchange on Which Registered | |
Common Stock, par value $0.001 | New York Stock Exchange |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes¨ Nox
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yesx No¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
Large accelerated filer¨ Accelerated filer¨ Non-accelerated filerx
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes¨ Nox
Estimated aggregate market value of the common equity held by nonaffiliates of the registrant at March 28, 2007: $16,267,000,000. The Registrant had no outstanding common equity held by nonaffiliates at June 30, 2006.
Number of shares of Common Stock, $0.001 par value, outstanding at March 28, 2007: 631,465,000
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SPECTRA ENERGY CORP
FORM 10-K FOR THE YEAR ENDED
DECEMBER 31, 2006
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This document includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on management’s beliefs and assumptions. These forward-looking statements are identified by terms and phrases such as “anticipate,” “believe,” “intend,” “estimate,” “expect,” “continue,��� “should,” “could,” “may,” “plan,” “project,” “predict,” “will,” “potential,” “forecast,” and similar expressions. Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:
| • | state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an effect on rate structure, and affect the speed at and degree to which competition enters the natural gas industries; |
| • | the outcomes of litigation and regulatory investigations, proceedings or inquiries; |
| • | the weather and other natural phenomena, including the economic, operational and other effects of hurricanes and storms; |
| • | the timing and extent of changes in commodity prices, interest rates and foreign currency exchange rates; |
| • | general economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities; |
| • | changes in environmental, safety and other laws and regulations; |
| • | the results of financing efforts, including the ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions; |
| • | declines is the market prices of equity securities and resulting funding requirements for defined benefit pension plans; |
| • | growth in opportunities, including the timing and success of efforts to develop domestic and international pipeline, storage, gathering, processing and other infrastructure projects and the effects of competition; |
| • | the performance of natural gas transmission and storage, distribution, and gathering and processing facilities; |
| • | the extent of success in connecting natural gas supplies to gathering, processing and transmission systems and in connecting to expanding gas markets; |
| • | the effect of accounting pronouncements issued periodically by accounting standard-setting bodies; |
| • | conditions of the capital markets and equity markets during the periods covered by the forward-looking statements; |
| • | the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture; and the success of the business following a merger, acquisition or divestiture; and |
| • | the ability to operate effectively as a stand-alone, publicly-traded company. |
In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than Spectra Energy Corp has described. Spectra Energy Corp undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
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PART I
Spectra Energy Corp (Spectra Energy) owns and operates a large and diversified portfolio of complementary natural gas-related energy assets and is one of North America’s premier midstream natural gas companies. For close to a century, Spectra Energy and its predecessor companies have developed critically important pipelines and related energy infrastructure connecting natural gas supply sources to premium markets. Spectra Energy operates in three key areas of the natural gas industry: transmission and storage, distribution and gathering and processing. The midstream sector of the natural gas industry is the link between the production of natural gas and the delivery of its components to end-use markets, and consists of the transmission and storage and the gathering and processing areas of the industry. Based in Houston, Texas, Spectra Energy provides transportation and storage of natural gas to customers in various regions of the Eastern and Southeastern United States, the Maritimes Provinces and the Pacific Northwest in the United States and Canada and in the province of Ontario in Canada. It also provides natural gas sales and distribution service to retail customers in Ontario, and natural gas gathering and processing services to customers in Western Canada. Spectra Energy also has a 50% ownership in DCP Midstream, LLC, (DCP Midstream), formerly Duke Energy Field Services, LLC, one of the largest natural gas gatherers and processors in the United States. Spectra Energy’s operations are subject to various federal, state, provincial and local laws and regulations.
Spectra Energy’s pipeline systems consist of approximately 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, the Maritimes Provinces, Ontario, Alberta and the Pacific Northwest. For 2006, Spectra Energy’s proportional throughput for its pipelines totaled 3,248 trillion British thermal units (TBtu), compared to 3,410 TBtu in 2005. These amounts include throughput on wholly-owned U.S. and Canadian pipelines and Spectra Energy’s proportional share of throughput on pipelines that are not wholly-owned. Spectra Energy’s storage facilities provide approximately 265 Bcf of storage capacity in the United States and Canada.
DCP Midstream gathers, compresses, processes, transports, trades and markets, and stores natural gas. DCP Midstream also fractionates, transports, gathers, treats, processes, trades and markets, and stores natural gas liquids, or NGLs. DCP Midstream is 50% owned by ConocoPhillips and 50% owned by Spectra Energy. DCP Midstream gathers raw natural gas through gathering systems located in major natural gas producing regions: Permian Basin, Mid-Continent, East Texas-North Louisiana, Gulf Coast, South, Central and Rocky Mountain.
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Spin-off from Duke Energy
On January 2, 2007, Duke Energy Corporation (Duke Energy) completed the spin-off of its natural gas businesses, primarily comprised of the Natural Gas Transmission and Field Services business segments of Duke Energy that were owned through Duke Energy’s wholly-owned subsidiary, Duke Capital LLC (now Spectra Energy Capital, LLC). Spectra Energy Capital, LLC (Spectra Energy Capital) was contributed by Duke Energy to Spectra Energy and all of the outstanding common stock of Spectra Energy was distributed to the Duke Energy shareholders. The Duke Energy shareholders received one share of Spectra Energy common stock for every two shares of Duke Energy common stock, resulting in the issuance of approximately 631 million shares of Spectra Energy on January 2, 2007.
Prior to the distribution by Duke Energy, Spectra Energy Capital implemented an internal reorganization in which the operations and assets of Spectra Energy Capital that were not associated with the natural gas businesses, were contributed by Spectra Energy Capital to Duke Energy or its subsidiaries. The contribution to Duke Energy, made in December 2006, included the following operations:
| • | International Energy business segment; |
| • | Crescent Resources (a real estate business); |
| • | The remaining portion of Spectra Energy Capital’s business formerly known as Duke Energy North America (DENA), which included unregulated power plant development and operations, and the marketing and trading of various energy services and commodities; and |
| • | Other miscellaneous operations, such as a fiber optic communications network and a project development services partnership, that were not associated with the natural gas operations of Spectra Energy. |
Following this internal reorganization and the distribution by Duke Energy to Spectra Energy, Spectra Energy Capital is a direct, wholly-owned subsidiary of Spectra Energy. All of the operating assets, liabilities and operations of Spectra Energy are held by Spectra Energy Capital, except for employee benefit plan assets and liabilities that were contributed by Duke Energy directly to Spectra Energy in a separation transaction. As a result of these spin-off steps, Spectra Energy Capital is treated as the predecessor entity for financial statement purposes. Accordingly, this Form 10-K includes the audited consolidated financial statements of Spectra Energy Capital. References throughout this document to the Consolidated Financial Statements or notes thereto are referring to the statements of Spectra Energy Capital.
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As of December 31, 2006, Spectra Energy’s businesses were reported by Spectra Energy Capital primarily in its Natural Gas Transmission and Field Services segments. As a result of the reorganization and spin-off of Spectra Energy from Duke Energy on January 2, 2007, Spectra Energy now manages its business in four reportable segments: U.S. Transmission, Western Canada Transmission & Processing, Distribution and Field Services. The first three segments are primarily included in Spectra Energy Capital’s Natural Gas Transmission segment and DCP Midstream is reported in the Field Services segment of Spectra Energy Capital. The remainder of Spectra Energy’s business operations is expected to be presented as “Other,” and consists of unallocated corporate costs, a wholly-owned captive insurance subsidiary, employee benefit plan assets and liabilities and other miscellaneous businesses.
The following sections describe the business and operations of each of Spectra Energy’s businesses. (For more information on the operating outlook of Spectra Energy and its segments, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations, Introduction—Executive Overview and Economic Factors for Duke Energy’s Business.” For financial information on Spectra Energy Capital’s business segments, see Note 3 to the Consolidated Financial Statements, “Business Segments.”)
Spectra Energy’s U.S. Gas Transmission business provides transportation and storage of natural gas for customers in various regions of the Eastern and Southeastern United States and the Maritimes Provinces in the United States and Canada. Spectra Energy’s U.S. pipeline systems consist of more than 12,800 miles of transmission pipelines with five primary transmission systems: Texas Eastern Transmission, L.P. (Texas Eastern), Algonquin Gas Transmission, LLC (Algonquin), East Tennessee Natural Gas, LLC (East Tennessee), Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, L.P. (collectively, Maritimes & Northeast Pipeline), and Gulfstream Natural Gas System, LLC (Gulfstream). These pipeline systems receive natural gas from major North American producing regions for delivery to markets. For 2006, U.S. gas transmission’s proportional throughput for its pipelines totaled 1,930 TBtu, compared to 1,953 TBtu in 2005. This includes throughput on wholly owned pipelines and its proportional share of throughput on pipelines that are not wholly owned. A majority of contracted transportation volumes are under long-term firm service agreements with local distribution company (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, and both firm and interruptible transportation services are provided to various customers on a short-term or seasonal basis. In the course of providing transportation services, U.S. Gas Transmission also processes natural gas on its Texas Eastern system. Demand on the pipeline systems is seasonal, with the highest throughput occurring during colder periods in the first and fourth calendar quarters.
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Texas Eastern
The Texas Eastern 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 (facilities that increase the pressure of gas to facilitate its pipeline transmission). 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 and has an ownership interest in a processing plant in Southern Louisiana. 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 billion cubic feet (Bcf). Texas Eastern is connected with two storage facilities through Market Hub Partners operations in Texas and Louisiana.
Algonquin
The Algonquin pipeline connects with Texas Eastern’s facilities in New Jersey, and extends approximately 250 miles through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it connects to the Maritimes & Northeast Pipeline. The system consists of approximately 1,100 miles of pipeline with six compressor stations.
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East Tennessee
East Tennessee’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. East Tennessee has a liquefied natural gas (LNG) storage facility in Tennessee with a total working capacity of 1.2 Bcf. East Tennessee also connects to Saltville Gas Storage Company L.L.C. (Saltville), a subsidiary of Spectra Energy, and other storage facilities in Virginia that have a working gas capacity of approximately 5 Bcf.
Maritimes & Northeast Pipeline
Maritimes & Northeast Pipeline transmission system is operated primarily through Spectra Energy’s 77.53% investments in Maritimes & Northeast Pipeline, LP and Maritimes & Northeast Pipeline, LLC. Maritimes & Northeast Pipeline transmission system extends approximately 900 miles from producing fields in Nova Scotia through New Brunswick, Maine, New Hampshire and Massachusetts, connecting to Algonquin in Beverly, Massachusetts. There are two compressor stations on the system.
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Gulfstream
Spectra Energy also has a 50% investment in Gulfstream, a 691-mile interstate natural gas pipeline system owned and operated jointly by Spectra Energy and The Williams Companies, Inc. Gulfstream has a capacity to transport 1.1 Bcf/day from Mississippi and Alabama, crossing the Gulf of Mexico to markets in central and southern Florida. Gulfstream has one compressor station.
Storage Services
Spectra Energy, through its subsidiary Market Hub Partners (MHP), owns and operates two natural gas storage facilities, Moss Bluff and Egan, with a total storage capacity of approximately 35 Bcf. The Moss Bluff facility consists of three storage caverns located in Southeast Texas and has access to five pipeline systems including the Texas Eastern system. The Egan facility consists of three storage caverns located in South Central Louisiana and has access to eight pipeline systems including the Texas Eastern system. MHP markets natural gas storage services to pipelines, LDCs, producers, end users and natural gas marketers. Texas Eastern and East Tennessee 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. East Tennessee also connects to Saltville Gas Storage Company L.L.C., a subsidiary of Spectra Energy. These underground reservoir and salt cavern storage facilities are located in Virginia and provide storage services to customers in the Southeastern United States.
Customers and Contracts
In general, Spectra Energy’s U.S. pipelines provide transportation services to LDC’s, electric power generators, industrial and commercial customers, as well as energy marketers. Transportation and storage services are provided under firm agreements where customers reserve capacity in pipelines and storage facilities. The vast majority of these agreements provide for fixed reservation charges that are paid monthly regardless of actual volumes transported on Spectra Energy’s pipelines or injected or withdrawn from our storage by customers plus a small variable component that is based on volumes transported to recover variable costs.
Spectra Energy also provides interruptible transportation and storage service agreements where customers can use capacity if it is available at the time of the request and payments under these services are based on volumes transported or stored. These U.S. operations also provide a variety of other value-added services including natural gas parking, loaning and balancing services to meet customers’ needs. These services are provided in accordance with tariffs that govern the provision of services and are approved by the appropriate regulatory agency that has jurisdiction over those systems.
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Competition
Spectra Energy’s U.S. transportation and storage businesses compete with similar facilities that serve its supply and market areas in the transportation and storage of natural gas. The principal elements of competition are rates, terms of service and flexibility and reliability of service.
The natural gas that Spectra Energy transports in its transmission business competes with other forms of energy available to its customers and end-users, including electricity, coal, propane and fuel oils. Several factors influence the demand for natural gas including price changes, the availability 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.
WESTERN CANADA TRANSMISSION & PROCESSING
Spectra Energy’s Western Canada Transmission & Processing business is comprised of the BC Pipeline and Field Services operations, the Midstream operations and the NGL Marketing operations.
BC Pipeline and Field Services provide natural gas transportation and gas gathering and processing services. BC Pipeline is regulated by the National Energy Board (NEB) under full cost of service regulation, and transports processed natural gas from facilities primarily in northeast British Columbia (BC) to markets in the lower mainland of BC and the US Pacific Northwest. The BC Pipeline has approximately 1,800 miles of transmission pipeline in British Columbia and Alberta, as well as 18 mainline compressor stations. For 2006, throughput for the BC Pipeline totaled 579 TBtu, compared to 619 TBtu in 2005. Total transmission capacity is approximately 2.0 Bcf per day.
The BC Field Services business, which is regulated by the NEB under a “light-handed” regulatory model, consists of raw gas gathering pipelines and gas processing facilities, primarily in northeast BC. These facilities provide services to natural gas producers to remove impurities from the raw gas stream including water, carbon dioxide, hydrogen sulfide and other substances. Where required, these facilities also remove various NGLs for subsequent sale. The BC Field Services business includes five gas processing plants located in British Columbia, 22 field compressor stations, and more than 1,800 miles of gathering pipelines.
The Midstream business provides similar gas gathering and processing services in BC and Alberta through Spectra Energy’s 46% interest in Spectra Energy Income Fund (Income Fund), formerly Duke Energy Income Fund, a Canadian Income Trust. The Midstream business consists of 13 natural gas processing plants and approximately 1,000 miles of gathering pipelines. Total processing capacity is approximately 870 MMcf per day.
The Empress NGL Marketing business provides NGL extraction, fractionation, transportation, storage and marketing services to both western Canadian producers and NGL customers throughout Canada and the northern tier of the U.S. Assets include, among other things, a majority ownership interest in an NGL extraction plant, an integrated NGL fractionation facility, an NGL transmission pipeline, seven terminals along the pipeline, two NGL storage facilities, and an NGL marketing and gas supply business. Total processing capacity of the Empress system is approximately 2.4 Bcf of gas per day. The Empress system is located in Western and Central Canada.
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Competition
Western Canada Transmission & Processing businesses compete with third-party midstream companies, exploration and production companies and pipelines in the transportation of natural gas. The Company competes directly with other pipeline facilities serving its market areas. The principal elements of competition are rates, terms of service, and flexibility and reliability of service. Customer demands for toll certainty and lower cost tailored services have promoted increased competition from other midstream service companies and producers. Spectra Energy believes it is able to offer a very competitive service offering along all of these dimensions due to its scale, geographical presence in important supply and market areas, financial stability and flexibility, and the strength of stakeholder relationships. Moreover, the presence of our existing pipeline assets, right of way, customer base and operations enables Spectra Energy to more quickly and cost effectively add capacity and service for customers in core markets. Spectra Energy’s reputation for customer service, project execution, stakeholder relations, reliability and predictable rates further enhance its competitive advantage. Taken as a whole, Spectra Energy believes its service offerings are among the most competitive in the sector.
Natural gas competes with other forms of energy available to our 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 Spectra Energy.
Customers & Contracts
Spectra Energy’s BC Pipeline provides: (i) transportation services from the outlet of natural gas processing plants in Northeast BC to LDCs, end use industrial and commercial customers, and exploration and production companies requiring transportation services to the nearest liquid natural gas trading hub; and (ii) transportation services primarily to downstream markets in the Pacific Northwest (both United States and Canada.) Major customer segments include local distribution companies, electric power generators, exploration and production companies, gas marketers, and industrial and commercial end users.
The largest portion of Spectra Energy’s business in Western Canada is represented by the BC Field Services and Midstream operations providing raw natural gas gathering and processing services to exploration and production companies under firm agreements which are primarily fee for service contracts. These operations provide both firm and interruptible service. Although both operations gather and process raw natural gas from the Western Canadian Sedimentary basin, they are significantly different in size and infrastructure within their respective regions.
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The NGLs extraction operation at Empress, Alberta produces approximately 50,000 barrels of NGLs per day comprised of approximately 50% ethane, 32% propane, 12% butanes and 6% condensate. All ethane is sold to Alberta-based petrochemical companies, the majority of propane is sold to propane wholesalers, butane is sold mainly into the motor gasoline refinery market, and condensate sales are directed to the crude blending market.
Spectra Energy provides retail distribution services in Canada through its subsidiary, Union Gas Limited (Union Gas). Union Gas owns primarily pipeline, storage and compression facilities used in the transportation, storage and distribution of natural gas. Union Gas’ 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 high-pressure transmission pipeline and six mainline compressor stations.
Union Gas distributes natural gas to approximately 1.3 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. Union Gas is regulated by the Ontario Energy Board (OEB) pursuant to the provisions of the Ontario Energy Board Act (1998) and is subject to regulation in a number of areas including rates.
Union Gas provides natural gas storage and transportation services for other utilities and energy market participants in Ontario, Quebec and the United States. Its storage and transmission system forms an important link in moving natural gas from Western Canadian and U.S. supply basins to Central Canadian and Northeastern U.S. markets. Transportation and storage customers are primarily Canadian natural gas transmission and distribution companies. A substantial amount of Union Gas’ annual transportation and storage revenue is generated by fixed demand charges under contracts with remaining terms of up to 11 years and an average outstanding term of 3.9 years.
Union Gas’ distribution services to power generation and industrial customers are affected by weather, economic conditions and the price of competitive energy sources. Most of Union Gas’ power generation, industrial and large commercial customers, and a portion of residential customers, purchase their natural gas 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, gas distribution margins are not affected by the source of customers’ gas supply.
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Competition
Union Gas is a regulated entity and is not generally subject to third-party competition within its distribution franchise area, although a recent decision of the OEB has permitted physical bypass of Union Gas’ facilities even within its distribution franchise area. In addition, other companies could enter Union Gas’ markets or regulations could change.
Customers and Contracts
The rates that Union Gas charges for its regulated services are subject to the approval of the OEB. Union Gas’ distribution service area extends throughout Northern Ontario from the Manitoba border to the North Bay/Muskoka area, through Southern Ontario from Windsor to just west of Toronto, and across Eastern Ontario from Port Hope to Cornwall. Union Gas’ franchise area has a population of approximately four million people and a diversified commercial and industrial base.
Union Gas also provides natural gas storage and transportation services for other utilities and energy market participants in Ontario, Quebec and the United States. Transportation and storage customers include large Canadian natural gas transmission and distribution companies.
Field Services includes Spectra Energy’s investment in DCP Midstream. Field Services gathers, compresses, processes, transports, trades and markets, and stores natural gas. DCP Midstream also fractionates, transports, gathers, treats, processes, trades and markets, and stores NGLs. In July 2005, Spectra Energy Capital completed the disposition of its 19.7% interest in DCP Midstream, which resulted in Spectra Energy Capital and ConocoPhillips becoming equal 50% owners in DCP Midstream. Additionally, the disposition transaction included the acquisition of ConocoPhillips’ interest in the Empress System and the transfer of the Canadian Midstream operations of Field Services to Spectra Energy Capital. Subsequent to the closing of the DCP Midstream disposition transaction, effective July 1, 2005, DCP Midstream was no longer consolidated into Spectra Energy Capital’s consolidated financial statements and is accounted for as an equity method investment. The Canadian Midstream operations and the Empress System were transferred to Spectra Energy’s Western Canada Transmission & Processing segment. Additionally, in February 2005, DCP Midstream sold its wholly-owned subsidiary, Texas Eastern Products Pipeline Company, LLC, the general partner of TEPPCO Partners L.P., and Spectra Energy sold its limited partner interest in TEPPCO Partners L.P., in each case to the same unrelated third party.
In 2005, DCP Midstream formed DCP Midstream Partners, LP a master limited partnership. DCP Midstream Partners, LP (DCPLP) completed an initial public offering in December 2005. As a result, DCP Midstream has a 42% ownership interest in DCPLP, consisting of a 40% limited partner ownership interest and a 2% general partner ownership interest. DCP Midstream owns 100% of the general partner of DCPLP and, therefore, consolidates DCPLP in its financial statements.
DCP Midstream operates in 16 states in the United States (Alabama, Arkansas, Colorado, Kansas, Louisiana, Maine, Massachusetts, Mississippi, New Mexico, New York, Oklahoma, Pennsylvania, Texas, Rhode Island, Vermont and Wyoming). DCP Midstream’s gathering systems include connections to several interstate and intrastate natural gas and NGL pipeline systems and one natural gas storage facility. DCP Midstream gathers raw natural gas through gathering systems located in seven major natural gas producing regions: Permian Basin, Mid-Continent, East Texas-North Louisiana, Gulf Coast, South, Central, and Rocky Mountain. DCP Midstream owns or operates approximately 56,000 miles of gathering and transmission pipe, with approximately 34,000 active receipt points.
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DCP Midstream’s 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. DCP Midstream processes the raw natural gas at 53 natural gas processing facilities.
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, butane, and natural gasoline) and then sold as components. DCP Midstream fractionates NGL raw mix at six processing facilities that it owns and operates and at four third-party-operated facilities in which it has an ownership interest. In addition, DCP Midstream operates a propane wholesale marketing business. DCP Midstream sells NGLs to a variety of customers ranging from large, multi-national 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. DCP Midstream markets residue gas directly or through its wholly-owned gas marketing company and its affiliates. DCP Midstream also stores residue gas at its 8 Bcf natural gas storage facility.
DCP Midstream 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. DCP Midstream 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. DCP Midstream believes there are additional opportunities to grow its services with its customer base.
DCP Midstream’s operating results are significantly impacted by changes in average NGL and crude oil prices, which increased approximately 10% and 15%, respectively, in 2006 compared to 2005. DCP Midstream closely monitors the risks associated with these price changes. (See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk” for a discussion of DCP Midstream’s exposure to changes in commodity prices.)
Competition
In gathering and processing natural gas and in marketing and transporting natural gas and NGLs, DCP Midstream 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/
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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.
Customers and Contracts
DCP Midstream sells NGLs to a variety of customers ranging from large, multi-national petrochemical and refining companies to small regional retail propane distributors. Substantially all of DCP Midstream’s NGL sales are made at market-based prices, including approximately 40% of its NGL production that is committed to ConocoPhillips and its affiliate, Chevron Phillips Chemical Company, LLC under existing contracts that have primary terms that expire on December 31, 2014. In 2006, ConocoPhillips and Chevron Phillips Chemical Company LLC, combined, represented approximately22% of DCP Midstream’s consolidated revenues.
The residual natural gas (primarily methane) that results from processing raw natural gas is sold at market-based prices to marketers and end-users. End-users include large industrial companies, natural gas distribution companies and electric utilities.
DCP Midstream purchases or takes custody of substantially all of its raw natural gas from producers, principally under the following types of contractual arrangements:
| • | Percentage-of-proceeds arrangements. In general, DCP Midstream purchases natural gas from producers, transports and processes it and then sells the residue natural gas and NGLs in the market. The payment to the producer is an agreed upon percentage of the proceeds from those sales. DCP Midstream’s revenues correlate directly with the price of natural gas and NGLs. |
| • | Fee-based arrangements. DCP Midstream receives a fee or fees for the various services it provides including gathering, compressing, treating, processing or transporting natural gas. The revenue DCP Midstream earns is directly related to the volume of natural gas that flows through its systems and is not directly dependent on commodity prices. |
| • | Keep-whole. DCP Midstream gathers raw natural gas from producers for processing and then markets the NGLs. DCP Midstream keeps the producer whole by returning an equivalent amount of natural gas after the processing is complete. DCP Midstream is exposed to the “frac spread” which is the value difference between the NGLs extracted and the natural gas returned to the producer. |
As defined by the terms of the above arrangements, DCP Midstream sells condensate, which is generally similar to crude oil and is produced in association with natural gas gathering and processing.
Spectra Energy purchases a variety of manufactured equipment and materials for use in operations and expansion projects. The primary equipment and materials utilized in operations and project execution processes are steel pipe, compression, valves, fittings and other consumables.
Spectra Energy operates a North American supply chain management network with employees dedicated to this function in the United States and Canada. The supply chain management group uses the scale of the Spectra Energy group to maximize the efficiency of supply networks where applicable.
The recovery in global economic growth, particularly in the North American energy sector, and rising international demand have led to increased demand levels and increased costs of steel used in certain of the manufactured equipment required by Spectra Energy’s operations. While some of these increases in price and supplier capacity will be offset through the use of strategic supplier contracts, Spectra Energy expects stable to rising prices and constant to extended lead times for many of these products in 2007 through 2009 compared to the previous three year period. The increasing costs and extended lead times are expected to primarily affect the expansion project execution process.
There can be no assurance that the ability to obtain sufficient equipment and materials will not be adversely affected by unforeseen developments. In addition, the price of equipment and materials may vary, perhaps substantially, from year to year.
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Most of Spectra Energy’s U.S. gas transmission pipeline and storage operations are regulated by the Federal Energy Regulatory Commission (FERC). The FERC regulates natural gas transportation in U.S. interstate commerce including the establishment of rates for services. The FERC also regulates the construction of U.S. interstate pipelines and storage facilities including extension, enlargement or abandonment of such facilities. In addition, certain operations are subject to oversight by state regulatory commissions.
FERC regulations restrict U.S. interstate pipelines from sharing transmission or customer information with energy affiliates and require that U.S. interstate pipelines function independently of their energy affiliates.
The FERC may propose and implement new rules and regulations affecting interstate natural gas transmission companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect certain transportation of gas by intrastate pipelines.
Spectra Energy’s U.S. gas transmission operations are subject to the jurisdiction of the Environmental Protection Agency (EPA) and state and local environmental agencies. For a discussion of environmental regulation, please see the section entitled “Environmental Matters.” Spectra Energy’s U.S. interstate natural gas pipelines are also subject to the regulations of the Department of Transportation (DOT) concerning pipeline safety.
The natural gas 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 jurisdiction similar to the FERC for regulating rates, regulating the operations of facilities and construction of any additional facilities. Spectra Energy’s BC Field Services business in Western Canada is regulated by the NEB pursuant to a framework for light-handed regulation under which the NEB acts on a complaints basis for rates associated with that business. Similarly, the rates charged by our midstream operations for gathering and processing services in Western Canada are regulated on a complaints basis by applicable provincial regulators. The Empress NGL businesses are not under any form of rate regulation.
The intrastate natural gas and NGL pipelines owned by DCP Midstream 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 DCP Midstream is subject to FERC regulation, but its natural gas gathering and processing activities are not subject to FERC regulation.
DCP Midstream is subject to the jurisdiction of the EPA and state and local environmental agencies. For more information, see “Environmental Matters.” DCP Midstream’s natural gas transmission pipelines and some gathering pipelines are also subject to the regulations of the DOT, and in some cases, state agencies, concerning pipeline safety.
Spectra Energy is subject to federal, state, provincial and local laws and regulations with regard to air and water quality, hazardous and solid waste disposal and other environmental matters. These regulations often impose substantial testing and certification requirements.
Environmental laws and regulations affecting Spectra Energy include, but are not limited to:
| • | The Clean Air Act, or CAA, and the 1990 amendments to the CAA, as well as state laws and regulations affecting air emissions (including State Implementation Plans related to existing and new national ambient air quality standards), which may limit new sources of air emissions. Spectra Energy’s natural gas processing, transmission, and storage assets are considered sources of air emissions, and thus are subject to the CAA. Owners and/or operators of air emission sources, such as Spectra Energy, are responsible for obtaining permits for existing and new sources of air emissions, and for annual compliance and reporting. |
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| • | The Federal Water Pollution Control Act, which requires permits for facilities that discharge wastewaters into the environment. The Oil Pollution Act (OPA), was enacted in 1990 and amends parts of the Clean Water Act and other statutes as they pertain to the prevention of and response to oil spills. OPA imposes certain spill prevention, control and countermeasure requirements. Although Spectra Energy is primarily a natural gas business, OPA affects its business primarily because of the presence of liquid hydrocarbons (condensate) in its offshore pipelines. |
| • | The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, which imposes liability for remediation costs associated with environmentally contaminated sites. Under CERCLA, any individual or entity that currently owns or in the past owned or operated a disposal site can be held liable and required to share in remediation costs, as well as transporters or generators of hazardous substances sent to a disposal site. Because of the geographical extent of its operations, Spectra Energy has disposed of waste at many different sites. |
| • | 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. As part of its business, Spectra Energy generates solid waste within the scope of these regulations and therefore must comply with such regulations. |
| • | The Toxic Substances Control Act, which requires that polychlorinated biphenyl (PCB) contaminated materials be managed in accordance with a comprehensive regulatory regime. Because of the historic use of lubricating oils containing PCBs, the internal surfaces of some of Spectra Energy’s pipeline systems are contaminated with PCBs and liquids and other materials removed from these pipelines must be managed in compliance with such regulations. |
| • | The National Environmental Policy Act, which requires federal agencies to consider potential environmental impacts in their decisions, including siting approvals. Many of Spectra Energy’s projects require federal agency review, and therefore the environmental effect of proposed projects is a factor in determining whether Spectra Energy will be permitted to complete proposed projects. |
| • | The Fisheries Act (Canada), which regulates activities near any body of water in Canada. |
| • | The Environmental Management Act (British Columbia); The Environmental Protection and Enhancement Act (Alberta); and The Environmental Protection Act (Ontario), are each provincial laws governing various aspects, including permitting and site remediation obligations, of Spectra Energy’s facilities and operations in those provinces. |
(For more information on environmental matters involving Spectra Energy, including possible liability and capital costs, see Notes4 and16 to the Consolidated Financial Statements, “Regulatory Matters,” and “Commitments and Contingencies—Environmental,” respectively.)
Except to the extent discussed in Note4 to the Consolidated Financial Statements, “Regulatory Matters,” and Note16 to the Consolidated Financial Statements, “Commitments and Contingencies—Environmental Matters,” compliance with federal, state, provincial and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Spectra Energy’s various business units and is not expected to have a material adverse effect on the competitive position, consolidated results of operations, cash flows or financial position of Spectra Energy.
For a discussion of Spectra Energy’s foreign operations and the risks associated with them, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations, 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,” respectively.
Spectra Energy had approximately 4,950 employees as of December 31, 2006, including approximately3,250 employees outside of the United States, all in Canada. In addition, DCP Midstream, Spectra Energy’s joint venture with ConocoPhillips, employed approximately 2,300 employees as of such date. Approximately1,500 of Spectra Energy’s employees, all of whom are located in Canada, are subject to collective bargaining agreements governing their employment with Spectra Energy. Spectra Energy reached agreements with all bargaining units with agreements subject to renewal in 2006.
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Spectra Energy was incorporated on July 28, 2006 as a Delaware corporation. Its principal executive offices are located at 5400 Westheimer Court, Houston, Texas 77056 and its telephone number is 713-627-5400. Spectra Energy electronically files reports with the Securities and Exchange Commission (SEC), including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies and amendments to such reports. The public may read and copy any materials that Spectra Energy files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, information about Spectra Energy, including its reports filed with the SEC, is available through Spectra Energy’s web site at http://www.spectraenergy.com. Such reports are accessible at no charge through Spectra Energy’s web site and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC. Spectra Energy’s website and the information contained on that site, or connected to that site, are not incorporated by reference into this report.
Glossary
Terms used to describe Spectra Energy’s business are defined below.
Accrual Model of Accounting (Accrual Model). An accounting term used by Spectra Energy 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, “Summary of Significant Accounting Policies,” 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), Spectra Energy Capital’s application of this term could differ from that of other companies.
Allowance for Funds Used During Construction (AFUDC). An accounting convention of regulators 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 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.
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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.
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 gas for ultimate consumption.
Mark-to-Market Model of Accounting (MTM Model). An accounting term used by Spectra Energy 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, “Summary of Significant Accounting Policies,” this term is applied to trading and undesignated non-trading derivative contracts. As this term is not explicitly defined within U.S. GAAP, Spectra Energy 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.
Portfolio. A collection of assets, liabilities, transactions or trades.
Residue Gas. Gas remaining after the processing of natural gas.
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.
Transmission System. 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.
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The following table sets forth information regarding Spectra Energy’s executive officers. Each of the individuals set forth below assumed their current position immediately before Spectra Energy’s listing on the New York Stock Exchange.
Name | Age | Position | ||||
Fred J. Fowler | 61 | President and Chief Executive Officer, Director | ||||
Martha B. Wyrsch | 49 | President and Chief Executive Officer – Spectra Energy Transmission, Director | ||||
Gregory L. Ebel | 42 | Group Executive and Chief Financial Officer | ||||
William S. Garner, Jr. | 57 | Group Executive, General Counsel and Secretary | ||||
Alan N. Harris | 53 | Group Executive and Chief Development Officer | ||||
Keith A. Crane | 42 | Vice President and Treasurer | ||||
Sabra L. Harrington | 44 | Vice President and Controller | ||||
Fred J. Fowler served as Group Executive and President of Duke Energy Gas from April 2006 until assuming his current position. Prior to then, Mr. Fowler served as President and Chief Operating Officer of Duke Energy Corporation from November 2002 until April 2006. Mr. Fowler served as Group Vice President of PanEnergy from 1996 until the PanEnergy merger in 1997, when he was named Group Vice President, Energy Transmission.
Martha B. Wyrsch served as President of Duke Energy Gas Transmission from March 2005 until assuming her current position. Ms. Wyrsch served as Group Vice President and General Counsel of Duke Energy Corporation from January 2004 until March 2005. Prior to then, Ms. Wyrsch served as Senior Vice President, Legal Affairs for Duke Energy Corporation from February 2003 until January 2004; Senior Vice President, Legal Affairs for Duke Energy Business Services from January 2003 until February 2003 and Senior Vice President and General Counsel of Duke Energy Field Services from February 2001 until January 2003.
Gregory L. Ebel served as President of Union Gas from January 2005 until assuming his current position. Prior to then, Mr. Ebel served as Vice President, Investor & Shareholder Relations of Duke Energy Corporation from November 2002 until January 2005. Mr. Ebel joined Duke Energy as Managing Director of Mergers and Acquisitions in connection with the company’s acquisition of Westcoast Energy. He served in that position from March 2002 until November 2002. At Westcoast Energy, Mr. Ebel served as Vice President of Strategic Development from March 1999 until March 2002.
William S. Garner, Jr. served as Group Vice President, Corporate Development of Duke Energy Gas Transmission from March 2006 until assuming his current position. Prior to joining Duke Energy, Mr. Garner served as managing director at Petrie Parkman & Co., a company which provides investment banking and advisory services to the energy industry and institutional investors. He served in this position from March 2000 until March 2006.
Alan N. Harris served as Group Vice President and Chief Financial Officer of Duke Energy Gas Transmission from February 2004 until assuming his current position. Prior to then, Mr. Harris served as Executive Vice President of Duke Energy Gas Transmission from January 2003 until February 2004; Senior Vice President, Strategic Development & Planning from March 2002 until January 2003 and Vice President, Controller & Strategic Planning from April 1999 until March 2002.
Keith A. Crane was hired in October 2006 by Duke Energy Gas Transmission to become Vice President and Treasurer of Spectra Energy in connection with the spin off. Prior to joining Duke Energy, Mr. Crane was an independent financial consultant from June 2005 to October 2006; from January 2005 to June 2005, he was engaged in charitable work for the Houston Heights Association, a historic neighborhood preservation organization. From March 2003 until January 2005 he was treasurer for Entergy-Koch, LP a private energy trading and gas transportation company and parent of Entergy-Koch Trading, LP and from August 2001 to March 2003 he was Treasurer of both Entergy-Koch, LP and Entergy-Koch Trading, LP.
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Sabra L. Harrington served as Vice President, Financial Strategy of Duke Energy Gas Transmission from February 2006 until assuming her current position. Prior to then, Ms. Harrington served as Vice President and Controller of Duke Energy Gas Transmission from August 2003 until February 2006. From March 2002 until August 2003, Ms. Harrington served as Controller of Duke Energy Gas Transmission and from April 1999 until March 2002, she served as Director, Gas Accounting, Forecasts, Budgets and Reporting.
The risk factors discussed herein relate specifically to risks associated with Spectra Energy subsequent to its spin-off from Duke Energy in January 2007. Accordingly, risks associated with operations that were distributed to Duke Energy on December 30, 2006 are not discussed in this section.
Reductions in demand for natural gas, or low levels in the market prices of commodities affects Spectra Energy’s operations and cash flows.
Declines in demand for natural gas as a result of economic downturns in Spectra Energy’s franchised gas service territory may reduce overall gas deliveries and reduce Spectra Energy’s cash flows, especially if its industrial customers reduce production and, therefore, consumption of gas. Spectra Energy’s gas gathering and processing businesses may experience a decline in the volume of natural gas gathered and processed at their plants, resulting in lower revenues and cash flows, as lower economic output reduces energy demand.
Lower demand for natural gas and lower prices for natural gas and natural gas liquids result from multiple factors that affect the markets where Spectra Energy transports, stores, distributes, gathers, and processes natural gas including:
| • | weather conditions, including abnormally mild winter or summer weather that cause lower energy usage for heating or cooling purposes, respectively; |
| • | supply of and demand for energy commodities, including any decreases in the production of natural gas which could negatively affect Spectra Energy’s processing business due to lower throughput; |
| • | capacity and transmission service into, or out of, Spectra Energy’s markets; and |
| • | petrochemical demand for natural gas liquids. |
The lack of availability of natural gas resources may cause customers to contract with alternative suppliers, which could materially adversely affect Spectra Energy’s sales, earnings, and cash flows.
Spectra Energy’s natural gas businesses are dependent on the continued availability of natural gas production and reserves. Prices for natural gas, regulatory limitations, or a shift in supply sources due to importing of foreign liquefied natural gas could adversely affect development of additional reserves and production that is accessible by Spectra Energy’s pipeline, gathering, processing and distribution assets. Lack of commercial quantities of natural gas available to these assets will cause customers to contract with alternative suppliers, thereby reducing their reliance on Spectra Energy’s services, which in turn would materially adversely affect Spectra Energy’s sales, earnings and cash flows.
Investments and projects located in Canada expose Spectra Energy to fluctuations in currency rates that may adversely affect cash flows and results of operations.
Spectra Energy is exposed to foreign currency risk from investments and operations in Canada. As of December 31, 2006, a 10% devaluation in the currency exchange rate of the Canadian dollar would result in an estimated net loss on the translation of Canadian currency earnings of approximately $25 million. The balance sheet would be negatively affected by approximately $460 million currency translation through the cumulative translation adjustment in accumulated other comprehensive income.
Natural gas gathering and processing operations are subject to commodity price risk which could result in economic losses in earnings and cash flows.
Spectra Energy has gathering and processing operations that consist of contracts to buy and sell commodities, including contracts for natural gas, natural gas liquids and other commodities that are settled by the
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delivery of the commodity or cash. Spectra Energy’s major commodity market risk is natural gas liquids prices, due primarily to its investment in DCP Midstream. Natural gas liquids prices historically track oil prices. At historical natural gas liquid-to-oil prices, a $1 per barrel move in oil prices would affect Spectra Energy’s pre-tax earnings from DCP Midstream by approximately $15 million.
With respect to the Empress system, a $1 change in the difference between the Btu-equivalent price of propane (used as a proxy for Empress’ NGL production) and the price of natural gas in Alberta, Canada (which represents theoretical gross margin for processing liquids from the gas and is commonly called the frac-spread) would affect Spectra Energy’s pre-tax earnings by approximately $25 million.
If prices of commodities significantly deviate from historical prices, if the price volatility or distribution of those changes deviates from historical norms, or if the correlation between natural gas liquids and oil prices deviates from historical norms, Spectra Energy’s approach to price risk management may not protect it from significant losses. In addition, adverse changes in energy prices may result in economic losses in earnings, cash flows and the balance sheet.
Spectra Energy’s business is subject to extensive regulation that affects operations and costs.
Spectra Energy’s U.S. assets and operations are subject to regulation by federal, state and local authorities, including regulation by the Federal Energy Regulatory Commission and by various authorities under federal, state and local environmental laws. The majority of Spectra Energy’s Canadian natural gas assets are subject to federal and provincial regulation including the National Energy Board and the Ontario Energy Board and likewise by federal and provincial environmental laws. Regulation affects almost every aspect of Spectra Energy’s business, including, among other things, the ability to determine terms and rates for services provided by some of its businesses; make acquisitions, issue equity or debt securities; and pay dividends.
In addition, regulators have taken actions to strengthen market forces in the gas pipeline industry, which have led to increased competition. In a number of key markets, interstate pipelines are facing competitive pressure from a number of new industry participants, such as alternative suppliers as well as traditional pipeline competitors. Increased competition driven by regulatory changes could have a material impact on Spectra Energy’s business, financial condition and operating results.
Transmission and storage, distribution, and gathering and processing activities involve numerous risks that may result in accidents or otherwise affect operations.
There are a variety of hazards and operating risks inherent in natural gas transmission and storage, distribution, and gathering and processing activities, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, and impairment of operations, any of which could result in substantial losses to Spectra Energy. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater. Spectra Energy does not maintain insurance coverage against all of these risks and losses, and any insurance coverage it might maintain may not fully cover the damages caused by those risks and losses for which it does maintain insurance. Therefore, should any of these risks materialize, it could have a material adverse effect on Spectra Energy’s business, financial condition and results of operations.
Spectra Energy is subject to numerous environmental laws and regulations, compliance with which requires significant capital expenditures, can increase cost of operations, and may affect or limit business plans, or expose Spectra Energy to environmental liabilities.
Spectra Energy is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can result in increased capital, operating, and other costs. These laws and regulations generally require Spectra Energy to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations can
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require significant expenditures, including expenditures for clean up costs and damages arising out of contaminated properties, and failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets. Spectra Energy may not be able to obtain or maintain from time to time all required environmental regulatory approvals for its operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals, if Spectra Energy fails to obtain and comply with them or if environmental laws or regulations change and become more stringent, the operation of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. No assurance can be made that the costs that will be incurred to comply with environmental regulations in the future will not have a material effect.
Spectra Energy’s Canadian businesses may be subject to the Kyoto Protocol. If Canada does implement a program to reduce greenhouse gas emissions, Spectra Energy may be obligated to reduce emissions and/or purchase emission credits. Due to the substantial uncertainty regarding what plan, if any, Canada will implement and whether this plan will apply to Spectra Energy’s facilities, Spectra Energy cannot estimate the potential effect of greenhouse gas regulation in Canada on business, financial condition, or results of operations.
Spectra Energy is involved in numerous legal proceedings, the outcome of which are uncertain, and resolution adverse to Spectra Energy could negatively affect cash flows, financial condition or results of operations.
Spectra Energy is subject to numerous legal proceedings. Litigation is subject to many uncertainties, and Spectra Energy cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which Spectra Energy is involved could require additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could have a material effect on cash flows and results of operations.
Spectra Energy relies on access to short-term money markets and longer-term capital markets to finance capital requirements and support liquidity needs, and access to those markets can be adversely affected, which could adversely affect cash flows or restrict businesses.
Spectra Energy’s business is financed to a large degree through debt. The maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from assets. Accordingly, Spectra Energy relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not satisfied by the cash flow from operations and to fund investments originally financed through debt. If Spectra Energy is not able to access capital at competitive rates, its ability to finance operations and implement its strategy may be adversely affected. Restrictions on Spectra Energy’s ability to access financial markets may also affect its ability to execute its business plan as scheduled. An inability to access capital may limit Spectra Energy’s ability to pursue improvements or acquisitions that it may otherwise rely on for future growth.
Spectra Energy maintains revolving credit facilities to provide back-up for commercial paper programs and/or letters of credit at various entities. These facilities typically include financial covenants which limit the amount of debt that can be outstanding as a percentage of the total capital for the specific entity. Failure to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper or letters of credit or borrowing under the revolving credit facility and could require other affiliates to immediately pay down any outstanding drawn amounts under other revolving credit agreements which could adversely affect cash flow or restrict businesses.
Spectra Energy may be unable to secure long-term transportation agreements, which could expose transportation volumes and revenues to increased volatility.
In the future, Spectra Energy may be unable to secure long-term transportation agreements for its gas transmission business as a result of economic factors, lack of commercial gas supply to its systems, increased competition, or changes in regulation. Without long-term transportation agreements, Spectra Energy’s revenues and contract volumes will be exposed to increased volatility and Spectra Energy cannot provide assurance that its pipelines will be utilized at similar levels or operate profitably. The inability to secure these agreements would materially adversely affect business, financial condition or results of operations.
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Native land claims have been asserted in British Columbia and Alberta which could affect future access to public lands, the success of which claims could have a significant adverse affect on Spectra Energy’s natural gas production and processing.
Certain aboriginal groups have claimed aboriginal and treaty rights over a substantial portion of public lands on which Spectra Energy’s facilities in British Columbia and Alberta, and the gas supply areas served by those facilities, are located. The existence of these claims, which range from the assertion of rights of limited use to aboriginal title, has given rise to some uncertainty regarding access to public lands for future development purposes. Such claims, if successful, could have a significant adverse effect on natural gas production in British Columbia and Alberta which could have a material adverse effect on the volume of natural gas processed at Spectra Energy’s facilities and of natural gas liquids and other products transported in the associated pipelines. Spectra Energy cannot predict the outcome of these claims or the impact they may ultimately have on business and operations.
If Spectra Energy or its rated subsidiaries are unable to maintain an investment grade credit rating, liquidity may be adversely affected and the cost of borrowing may increase. Spectra Energy cannot be sure that Spectra Energy or its rated subsidiaries will obtain or maintain investment grade credit ratings.
Spectra Energy’s senior unsecured long-term debt is currently rated investment grade by various rating agencies. If the rating agencies were to rate Spectra Energy or its rated subsidiaries below investment grade, such entity’s borrowing costs would increase, perhaps significantly. In addition, the entity would likely be required to pay a higher interest rate in future financings, and its potential pool of investors and funding sources would likely decrease. Furthermore, if Spectra Energy’s short-term debt rating were to be below tier 2 (e.g. A-2/P-2, S&P and Moody’s respectively), access to the commercial paper market could be significantly limited. There are requirements for Spectra Energy to post collateral or a letter of credit if its S&P credit rating falls below BBB—. Any downgrade or other event negatively affecting the credit ratings of Spectra Energy’s subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase Spectra Energy’s need to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and borrowing availability of the consolidated group.
Protecting against potential terrorist activities requires significant capital expenditures and a successful terrorist attack could adversely affect Spectra Energy’s business.
Future acts of terrorism and any possible reprisals as a consequence of any action by the United States and its allies could be directed against companies operating in the United States. This risk is particularly great for companies, like Spectra Energy, operating in any energy infrastructure industry that handles volatile gaseous and liquid hydrocarbons. The potential for terrorism has subjected Spectra Energy’s operations to increased risks that could have a material adverse effect on business. In particular, Spectra Energy may experience increased capital and operating costs to implement increased security for its facilities and pipelines, such as additional physical facility and pipeline security and additional security personnel. Moreover, any physical damage to high profile facilities resulting from acts of terrorism may not be covered, or covered fully, by insurance. Spectra Energy may be required to expend material amounts of capital to repair any facilities, the expenditure of which could adversely affect cash flow and business.
Due to proposed or potential changes in Canadian tax laws, Spectra Energy may not be able to fully realize its goal of utilizing tax-efficient structures to improve its cost of capital, optimize returns on assets, and finance portfolio growth.
Spectra Energy’s business strategy includes utilizing tax-efficient structures, such as master limited partnerships (MLP) and Canadian income trusts. On October 31, 2006, the Minister of Finance of Canada announced proposed changes to the income tax treatment of “flow-through entities,” including income trusts. If the proposal is implemented in its current form, income trusts will be subject to tax at corporate rates on the taxable portion of their distributions. Further, unitholders will be treated as if they have received a dividend equal to the taxable portion of their distributions, and will be taxed accordingly. These proposed changes will generally apply beginning in the 2007 taxation year for trusts that begin to be publicly-traded after October 2006, but would only apply beginning with the 2011 taxation year to those income trusts, such as the Income Fund, that were already publicly traded at the time of the announcement. While the proposed Canadian changes have not yet
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been implemented, such changes could have an adverse effect on Spectra Energy’s ability to fully implement its business strategy which may affect its access to capital and the ability to maximize returns on the assets it might hold, and result in an inability to finance portfolio growth through the use of this vehicle.
Risks Relating to the Separation of Spectra Energy from Duke Energy
Spectra Energy may be unable to achieve some or all of the benefits that it expects to achieve from the separation from Duke Energy.
Spectra Energy may not be able to achieve the full strategic and financial benefits that it expects will result from the separation from Duke Energy or such benefits may be delayed or may not occur at all.
| • | Prior to the separation, Spectra Energy’s business was operated by Duke Energy as part of its broader corporate organization. Duke Energy or its affiliates performed various corporate functions for Spectra Energy, including, but not limited to, accounts payable, cash management, treasury, tax administration, certain governance functions (including compliance with the Sarbanes-Oxley Act of 2002 and internal audit) and external reporting. Spectra Energy’s historical financial results reflect allocations of corporate expenses from Duke Energy for these and similar functions. These allocations may be more or less than Spectra Energy may incur in the future. |
| • | Spectra Energy’s business was integrated with the other businesses of Duke Energy. Historically, Spectra Energy shared economies of scope and scale in costs, employees, vendor relationships and certain customer relationships with Duke Energy. The Transition Services Agreement entered into with Duke Energy may not capture the benefits Spectra Energy’s businesses have enjoyed as a result of having been integrated with the other businesses of Duke Energy. The loss of these benefits may have an adverse effect on business, results of operations and financial condition following the separation. |
| • | Future borrowing costs for Spectra Energy’s business may be higher than Duke Energy’s borrowing costs prior to the separation. |
| • | Other significant changes may occur in Spectra Energy’s cost structure, management, financing and business operations as a result of operating within Spectra Energy as a company separate from Duke Energy. |
Spectra Energy may be unable to make, on a timely or cost-effective basis, the changes necessary to operate as a separate, publicly-traded company, and Spectra Energy may experience increased costs as a result of the separation.
Following the separation, Duke Energy is contractually obligated to provide to Spectra Energy and its subsidiaries only those services specified in the Transition Services Agreement and other agreements entered into with Duke Energy in connection with the separation. Spectra Energy may be unable to replace in a timely manner or on comparable terms, the services that Duke Energy previously provided that are not specified in the Transition Services Agreement or the other agreements. Also, upon the expiration of the Transition Services Agreement or other agreements, many of the services that are covered in such agreements will be provided internally or by unaffiliated third parties, and Spectra Energy expects that in some instances it may incur higher costs to obtain such services than it incurred under the terms of such agreements. In addition, if Duke Energy does not continue to perform effectively the transition services and the other services that are called for under the Transition Services Agreement and the other agreements, Spectra Energy may not be able to operate its business effectively and profitability may decline.
Spectra Energy’s agreements with Duke Energy may not reflect terms that would have resulted from arm’s-length negotiations among unaffiliated third parties.
The agreements related to the separation from Duke Energy were prepared in the context of the separation from Duke Energy while Spectra Energy was still part of Duke Energy and, accordingly, may not reflect terms that would have resulted from arm’s-length negotiations among unaffiliated third parties. The terms of the agreements were prepared in the context of the separation related to, among other things, allocation of assets, liabilities, rights, indemnifications and other obligations between Duke Energy and Spectra Energy.
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Spectra Energy will be responsible for certain contingent and other corporate liabilities related to the natural gas transmission and storage, distribution, and gathering and processing businesses of Duke Energy.
Under the Separation and Distribution Agreement and Tax Matters Agreement, Spectra Energy will assume and be responsible for certain contingent and other corporate liabilities related to the natural gas transmission and storage, distribution, and gathering and processing businesses of Duke Energy (including associated costs and expenses, whether arising prior to, at, or after the distribution) and Spectra Energy may be required to indemnify Duke Energy for these liabilities which may have a material effect on financial condition and results of operations. In addition, Spectra Energy may also be responsible for sharing unknown liabilities that do not relate to either its business following the separation or the business of Duke Energy following the separation (for example, liabilities associated with certain corporate activities not specifically attributable to either business).
Spectra Energy’s executive officers and some of its directors may have or may hold Duke Energy equity awards which may create, or may create the appearance of, conflicts of interest.
Because of their current or former positions with Duke Energy, substantially all of the Spectra Energy directors and executive officers own shares of Duke Energy common stock, options to purchase shares of Duke Energy common stock or other equity awards based on Duke Energy common stock. Upon Duke Energy’s distribution of all of Spectra Energy’s shares of common stock to Duke Energy shareholders, these options and other equity awards were converted into options and other equity awards based in part on Duke Energy common stock and in part on Spectra Energy common stock. Accordingly, following Duke Energy’s distribution of Spectra Energy to shareholders, these officers and non-employee directors will own shares of both Duke Energy and Spectra Energy common stock and/or hold options to purchase common stock and other equity awards based on shares of common stock of both Duke Energy and Spectra Energy. The individual holdings of common stock, options to purchase common stock and other equity awards based on common stock of Duke Energy may be significant for some of these persons compared to these persons’ total assets. Even though Spectra Energy’s board of directors include directors who are independent from Duke Energy, Spectra Energy’s executive officers were previously employees of Duke Energy. Ownership by those directors and officers of common stock, options to purchase common stock and other equity awards based on common stock of Duke Energy may create, or may create the appearance of, conflicts of interest when those directors and officers are faced with decisions that could have different implications for Duke Energy than the decisions do for Spectra Energy.
Spectra Energy might not be able to engage in desirable strategic transactions and equity issuances following the distribution.
To preserve the tax-free treatment to Duke Energy of the distribution, under the Tax Matters agreement that Spectra Energy entered into with Duke Energy, for the two year period following the distribution, Spectra Energy may be prohibited, except in specified circumstances, from issuing equity securities to satisfy financing needs, acquiring businesses or assets with equity securities, or engaging in other actions or transactions that could jeopardize the tax-free status of the distribution. These restrictions may limit Spectra Energy’s ability to pursue strategic transactions or engage in new business or other transactions that may maximize the value of its business.
Risks Relating to Spectra Energy’s Common Stock
Substantial sales of Spectra Energy’s common stock may occur in connection with its spin-off from Duke Energy, which could cause its stock price to decline.
It is possible that some shareholders of Duke Energy that received shares of Spectra Energy common stock in the spin-off transaction, including possibly some of Spectra Energy’s largest shareholders, may sell their shares of Spectra Energy common stock for reasons such as that Spectra Energy’s business profile or market capitalization as a separate, publicly-traded company does not fit their investment objectives. The sales of significant amounts of Spectra Energy common stock or the perception in the market that this will occur may result in the lowering of the market price of Spectra Energy’s common stock.
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Provisions in Spectra Energy’s certificate of incorporation, by-laws and of Delaware law may prevent or delay an acquisition of the company, which could decrease the trading price of Spectra Energy common stock.
Spectra Energy’s certificate of incorporation, by-laws and Delaware law contain provisions that are intended to deter coercive takeover practices and inadequate takeover bids by making such practices or bids unacceptably expensive to the raider and to encourage prospective acquirors to negotiate with its board of directors rather than to attempt a hostile takeover. These provisions include, among others:
| • | a board of directors that is divided into three classes with staggered terms; |
| • | inability of Spectra Energy’s shareholders to act by written consent; |
| • | rules regarding how shareholders may present proposals or nominate directors for election at shareholder meetings; |
| • | the right of Spectra Energy’s board of directors to issue preferred stock without shareholder approval; and |
| • | limitations on the right of shareholders to remove directors. |
Delaware law also imposes some restrictions on mergers and other business combinations between Spectra Energy and any holder of 15% or more of our outstanding common stock.
Spectra Energy believes these provisions are important for a new public company and protect its shareholders from coercive or otherwise potentially unfair takeover tactics by requiring potential acquirors to negotiate with its board of directors and by providing the board of directors with more time to assess any acquisition proposal. These provisions are not intended to make Spectra Energy immune from takeovers. However, these provisions apply even if the offer may be considered beneficial by some shareholders and could delay or prevent an acquisition that Spectra Energy’s board of directors determines is not in the best interests of the company and its shareholders.
Although Spectra Energy currently anticipates paying dividends, there cannot be any assurance that dividends will be paid in the future.
Currently, Spectra Energy anticipates paying dividends of approximately 60% of its anticipated annual net income per share of common stock. However, there can be no assurance that Spectra Energy will have sufficient surplus under Delaware law to be able to pay dividends in future periods. This may result from extraordinary cash expenses, actual expenses exceeding contemplated costs, funding of capital expenditures, or increases in reserves. The declaration and payment of dividends by Spectra Energy will be subject to the sole discretion of its board of directors and will depend upon many factors, including its financial condition, earnings, capital requirements of its operating subsidiaries, covenants associated with certain of its debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by its board of directors. If Spectra Energy does not pay dividends, the price of its common stock may decline.
Item 1B. Unresolved Staff Comments.
None.
At December 31, 2006, Spectra Energy had over 100 primary facilities located in the United States and Canada. Spectra Energy generally owns sites associated with its major pipeline facilities, such as compressor stations. However, it generally operates its transmission facilities—transmission and distribution pipelines—using rights of way pursuant to easements to install and operate pipelines but does not own the fee of underlying realty. Except as described in Note 14 to the Consolidated Financial Statements “Debt and Credit Facilities,” none of Spectra Energy’s property was secured by mortgages or other material security interests at December 31, 2006.
Spectra Energy’s corporate headquarters are located at 5400 Westheimer Court, Houston, Texas 77056, which is a leased facility. The lease expires in April, 2018. It also maintains major offices in Calgary, Alberta; Vancouver, British Columbia; Chatham, Ontario; Boston, Massachusetts; Tampa, Florida; Halifax, Nova Scotia;
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and Nashville, Tennessee. For a description of its material properties, please see Item 1 of this report. Spectra Energy’s property, plant and equipment includes buildings, technical equipment and other equipment capitalized under capital lease agreements. For more details, please refer to Note 13 to the Consolidated Financial Statements “Property, Plant and Equipment.”
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.”
Item 4. Submission of Matters to a Vote of Security Holders
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market for Common Stock
Spectra Energy’s common stock is traded on the New York Stock Exchange (NYSE) under the symbol “SE.” A “when-issued” trading market for Spectra Energy’s common stock on the NYSE began on December 14, 2006 and “regular-way” trading of Spectra Energy’s common stock began on January 3, 2007. Prior to December 14, 2006, there was no market for Spectra Energy’s common stock. At December 31, 2006, all of the outstanding shares of common stock of Spectra Energy were owned by Duke Energy.
Holders of Record
As of March 28, 2007, there were approximately 161,000 holders of record of Spectra Energy’s common stock and approximately 660,000 beneficial owners.
Dividends
Spectra Energy did not pay any cash dividends for the fiscal years ending 2006 and 2005. On March 15, 2007, Spectra Energy paid a cash dividend on its common stock of $0.22 per share, to shareholders of record on the close of business February 16, 2007. Currently, Spectra Energy anticipates a dividend payout ratio of approximately 60% of its anticipated annual net income per share of common stock. The declaration and payment of dividends by Spectra Energy will be subject to the sole discretion of the board of directors and will depend upon many factors, including Spectra Energy’s financial condition, earnings, capital requirements of its operating subsidiaries, covenants associated with certain of its debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by the board of directors. Spectra Energy anticipates increasing its dividend in an amount consistent with underlying growth in earnings.
Unregistered Sales
In connection with Spectra Energy’s incorporation on July 28, 2006, Spectra Energy issued to Duke Energy 1,000 shares of Spectra Energy’s common stock, par value $.001 per share, in exchange for a $1.00 contribution. The issuance of such shares of Spectra Energy common stock to Duke Energy was exempt from registration under Section 4(2) of the Securities Act of 1934, as amended.
Market Repurchases
Spectra Energy has not made any repurchases of shares of its common stock.
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Item 6. Selected Financial Data.
Spectra Energy Capital, LLC(a)
The following table presents Spectra Energy Capital’s selected historical financial data. The historical financial data are not necessarily indicative of any future performance or what the financial position and results of operations would have been if Spectra Energy Capital had operated as a separate, stand-alone entity during the periods presented.
| 2006 | 2005 | 2004 | 2003(c) | 2002 | |||||||||||||||
| (in millions) | |||||||||||||||||||
Statement of Operations | |||||||||||||||||||
Operating revenues | $ | 4,532 | $ | 9,454 | $ | 13,433 | $ | 11,937 | $ | 8,559 | |||||||||
Operating expenses | 3,334 | 8,123 | 11,757 | 11,837 | 7,622 | ||||||||||||||
Gains (losses) on sales of other assets and other, net | 47 | 522 | (349 | ) | 3 | — | |||||||||||||
Operating income | 1,245 | 1,853 | 1,327 | 103 | 937 | ||||||||||||||
Other income and expenses, net | 736 | 1,668 | 306 | 373 | 374 | ||||||||||||||
Interest expense | 605 | 675 | 858 | 915 | 760 | ||||||||||||||
Minority interest expense | 45 | 511 | 214 | 138 | 93 | ||||||||||||||
Earnings (loss) from continuing operations before income taxes | 1,331 | 2,335 | 561 | (577 | ) | 458 | |||||||||||||
Income tax expense (benefit) from continuing operations | 395 | 926 | 1,268 | (260 | ) | 125 | |||||||||||||
Income (loss) from continuing operations | 936 | 1,409 | (707 | ) | (317 | ) | 333 | ||||||||||||
Income (loss) from discontinued operations, net of tax | 308 | (731 | ) | 593 | (1,381 | ) | (38 | ) | |||||||||||
Income (loss) before cumulative effect of change in accounting principle | 1,244 | 678 | (114 | ) | (1,698 | ) | 295 | ||||||||||||
Cumulative effect of change in accounting principle, net of tax and minority interest | — | (4 | ) | — | (160 | ) | — | ||||||||||||
Net income (loss) | $ | 1,244 | $ | 674 | $ | (114 | ) | $ | (1,858 | ) | $ | 295 | |||||||
Ratio of Earnings to Fixed Charges(d) | 3.1 | 4.3 | 1.7 | — | (b) | 1.4 | |||||||||||||
Balance Sheet Total assets | $ | 20,345 | $ | 35,056 | $ | 37,183 | $ | 39,892 | $ | 45,109 | |||||||||
Long-term debt including capital leases, less current maturities | $ | 7,726 | $ | 8,790 | $ | 11,288 | $ | 13,655 | $ | 15,703 | |||||||||
| (a) | Significant transactions reflected in the results above include: 2006 transfer of certain businesses to Duke Energy in December 2006 (see Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies”), 2006 transfer of former DENA Midwestern assets to Duke Energy Ohio (see Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies”), 2006 Crescent joint venture transaction and subsequent deconsolidation effective September 7, 2006 (see Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”), 2005 DENA disposition (see Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”), 2005 deconsolidation of DCP Midstream effective July 1, 2005 (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”), 2005 DCP Midstream sale of TEPPCO (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”), 2004 tax charge as a result of the conversion to an LLC (see Note 5 to the Consolidated Financial Statements, “Income Taxes”), 2004 DENA sale of the Southeast plants (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”), and 2003 DENA charges (see Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). |
| (b) | Earnings were inadequate to cover fixed charges by $500 million for the year ended December 31, 2003. |
| (c) | As of January 1, 2003, Spectra Energy Capital adopted the remaining provisions of Emerging Issues Task Force (EITF) 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-03) and SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143). In accordance with the transition guidance for these standards, Spectra Energy Capital recorded a net-of-tax and minority interest cumulative effect adjustment for change in accounting principles. |
| (d) | Includes pre-tax gains of approximately $0.9 billion, net of minority interest, related to the sale of TEPPCO GP and LP in 2005 (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). |
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
INTRODUCTION
Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Notes for the years ended December 31, 2006, 2005 and 2004.
EXECUTIVE OVERVIEW
In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses that were owned through Duke Energy’s wholly-owned subsidiary, Duke Capital LLC (now Spectra Energy Capital, LLC). On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, including Spectra Energy Capital and its Natural Gas Transmission and Field Services segments to Duke Energy’s shareholders. Spectra Energy Capital was contributed by Duke Energy to Spectra Energy and all of the outstanding common stock of Spectra Energy was distributed to the Duke Energy shareholders. The Duke Energy shareholders received one share of Spectra Energy common stock for every two shares of Duke Energy common stock, resulting in the issuance of approximately 631 million shares of Spectra Energy on January 2, 2007.
Prior to the distribution by Duke Energy, Spectra Energy Capital implemented an internal reorganization in which the operations and assets of Spectra Energy Capital that were not associated with the natural gas businesses, were contributed by Spectra Energy Capital to Duke Energy or its subsidiaries. The contribution to Duke Energy included the following operations:
| • | International Energy business segment; |
| • | Crescent Resources (a real estate business); |
| • | The remaining portion of Spectra Energy Capital’s business formerly known as DENA (Duke Energy North America), which included unregulated power plant development and operations, and the marketing and trading of various energy services and commodities; and |
| • | Other miscellaneous operations, such as a fiber optic communications network and a project development services partnership, that were not associated with the natural gas operations of Spectra Energy. |
Following this internal reorganization and the distribution by Duke Energy to Spectra Energy, Spectra Energy Capital became a direct, wholly-owned subsidiary of Spectra Energy. All of the operating assets, liabilities and operations of Spectra Energy are held by Spectra Energy Capital, except for employee benefit plan assets and liabilities that were contributed by Duke Energy directly to Spectra Energy in the separation transaction. As a result of these spin-off steps, Spectra Energy Capital is treated as the predecessor entity of Spectra Energy for financial statement purposes. Accordingly, this Form 10-K includes the audited consolidated financial statements of Spectra Energy Capital. References throughout this document, including the discussions throughout this Management’s Discussion and Analysis of Financial Condition and Results of Operations, to the consolidated financial statements or notes thereto are referring to the statements of Spectra Energy Capital. Future financial statements and related information of Spectra Energy will reflect that of Spectra Energy Capital for all prior periods reported.
The results of operations of substantially all of the businesses retained by Duke Energy are reflected as discontinued operations in the accompanying Consolidated Statements of Operations for all periods presented. Transferred corporate services entities remain presented within continuing operations of Spectra Energy Capital for all periods presented since Spectra Energy Capital will continue to provide similar corporate services to support the operations of Spectra Energy.
2006 Financial Results. For the year-ended December 31, 2006, Spectra Energy Capital reported income from continuing operations of $936 million as compared to income from continuing operations of $1,409 million for the year ended December 31, 2005. The decrease in income from continuing operations was due primarily to
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the absence of prior year pre-tax gains of approximately $900 million (net of minority interest of approximately $343 million) recorded in 2005 related to DCP Midstream’s sale of TEPPCO GP, which is the general partner of TEPPCO LP and Spectra Energy Capital’s sale of its limited partner interests in TEPPCO LP, and an approximate $575 million gain recorded in 2005 as a result of the DCP Midstream disposition transaction, partially offset by the absence of prior year hedge losses in 2006 associated with de-designated Field Services’ hedges and reduced income tax expense in 2006, as discussed below. The highlights for 2006 include the following:
| • | Natural Gas Transmission’s results were flat from 2005 to 2006, but were affected by strong commodity prices related to processing activities and higher operating and maintenance expenses. |
| • | Field Services experienced lower earnings in 2006 primarily as a result of the 2005 gains on the sale of the TEPPCO investments and the transfer of a 19.7% interest in DCP Midstream to ConocoPhillips in July 2005, which resulted in the deconsolidation of the investment in DCP Midstream. Results in 2006 were favorably affected by strong commodity prices. |
| • | Other experienced lower losses in 2006 primarily as a result of prior year impact of realized and unrealized mark-to-market impacts on certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk and decreased captive insurance expenses due to the transfer of ownership in Bison to Duke Energy effective April 1, 2006. |
| • | Income tax expense from continuing operations, net of tax, was lower in 2006 as a result of a decrease in earnings from continuing operations before income taxes and a reduction in the effective tax rate. The reduction in the effective tax rate resulted primarily from a benefit to state taxes due to a reduction in the unitary state tax rate in 2006 as a result of Duke Energy’s merger with Cinergy. |
| • | Income (loss) from discontinued operations improved in 2006 compared to the prior year due primarily to an approximate $0.7 billion after-tax impairment charge (approximately $0.9 billion pre-tax) in 2005 related to the former DENA segment, as a result of the decision to exit substantially all former DENA operations except for the Midwestern operations, remaining Southeastern operations, and the related investment in DETM. For purposes of these financial statements, the Midwestern operations are included in discontinued operations for all periods presented as the Midwestern assets and related operations were transferred by Spectra Energy Capital to Duke Energy Ohio in April 2006. Additionally, results reflect the net of tax impacts of the operations of International Energy and Spectra Energy Capital’s interest in Crescent, including an approximate $250 million pre-tax gain recorded in 2006 on Spectra Energy Capital’s sale of an effective 50% of its interest in Crescent, and various operations previously included in Other, which are classified in discontinued operations as a result of Spectra Energy Capital transferring these operations to Duke Energy in December 2006, and the impacts of termination or sale of the final remaining contracts at former DENA. |
Spectra Energy’s Strategy. Following the spin-off from Duke Energy, Spectra Energy expects to benefit from a sharper focus on core business and growth opportunities, with greater flexibility in accessing capital markets and responding to changes in the industry.
Spectra Energy’s primary business objective is to provide value added, reliable and safe services to customers, which Spectra Energy believes will create opportunities to deliver increased dividends per share and value to shareholders of Spectra Energy. Spectra Energy intends to accomplish this objective by executing the following overall business strategies:
| • | capitalize on the size and attributes of existing assets; |
| • | pursue organic growth, expansion projects, strategic acquisitions and other business opportunities arising in Spectra Energy’s market and supply areas; |
| • | continue to develop operational efficiencies among existing assets; |
| • | utilize tax-efficient financial structures, such as MLPs, to improve access to capital, optimize returns on assets and finance portfolio growth; |
| • | continue to focus on operational excellence including safety, reliability, compliance and stringent cost management; and |
| • | retain and enhance customer and other stakeholder relationships. |
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Through the continued execution of these strategies, Spectra Energy expects to grow and strengthen the overall business, capture new growth opportunities and deliver value to Spectra Energy’s stakeholders.
Economic Factors for Spectra Energy’s Business. At December 31, 2006, Spectra Energy operated within the business unit structure of Duke Energy, as the Natural Gas Transmission and Field Services segments of Duke Energy. The business units of Duke Energy, including the Natural Gas Transmission, Field Services, U.S. Franchised Electric and Gas and International Energy operations, were generally managed autonomously from one another. Therefore, the primary business operations of Spectra Energy and Spectra Energy Capital are not expected to change significantly from the previous operating environment of the Natural Gas Transmission and Field Services segments. There were certain shared functions among Duke Energy units, including shared corporate and business services, as well as shared strategic initiatives and capital resource allocations that will no longer be reflected in Spectra Energy’s results of operations. The scope of Spectra Energy’s corporate management will increase as a result of the separation from Duke Energy because Spectra Energy will be creating new governance and business support functions—previously provided by Duke Energy—that are required in order to operate as a separate company.
Spectra Energy’s regulated businesses are generally economically stable and are not significantly impacted in the long-term by seasonal temperature variations and changing commodity prices. However, all of Spectra Energy’s businesses can be negatively affected by sustained downturns or sluggishness in the economy, including reductions in demand and low market prices for natural gas and NGLs, all of which are beyond Spectra Energy’s control, and could impair the ability to meet long-term goals.
Subsequent to the deconsolidation of DCP Midstream, and the December 2006 distribution of the operations discussed above to Duke Energy, substantially all of Spectra Energy’s revenues are based on regulated tariff rates, which include the recovery of certain fuel costs. However, lower overall economic output would cause Spectra Energy to experience a decline in the volume of natural gas transported and distributed or gathered and processed at its plants, resulting in lower earnings and cash flows. This decline would primarily affect distribution revenues in the short-term. Processing revenues are also impacted by volumes of natural gas made available to the system, which is primarily driven by levels of natural gas drilling activity. Transmission revenues could be impacted by long-term economic declines that could result in the non-renewal of long-term contracts at time of expiration. Pipeline transportation and storage customers continue to renew most contracts as they expire.
Spectra Energy’s key markets—the Northeast United States, Florida and the Southeast United States, Ontario and the Pacific Northwest—are projected to continue to exhibit higher than average annual growth in natural gas demand versus the North American and U.S. Lower 48 average growth rates through 2015. This demand growth is primarily driven by the natural gas-fired electric generation sector. The natural gas industry is currently experiencing a significant shift in the sources of supply, and this dramatic change is affecting Spectra Energy’s growth strategies. Traditionally, supply to Spectra Energy’s markets has come from the Gulf Coast region, onshore and offshore, as well as from fields in Western Canada and Eastern Canada. The national supply profile is shifting to new, and, in some cases, non-conventional sources of gas from basins in the Rockies, Mid-Continent and East Texas. In addition, the natural gas supply outlook will be shaped by new LNG re-gasification facilities being built. LNG will clearly be an important new source of supply, but the timing and extent of incremental supply from LNG is yet to be determined and, at present, LNG remains a small percentage of the overall supply to the markets Spectra Energy serves. These supply shifts are shaping the growth strategies that Spectra Energy will pursue, and therefore, will affect the nature of the projects anticipated in the capital and investment expenditure increases discussed below in “—Liquidity and Capital Resources.”
Spectra Energy’s businesses in the U.S. are subject to regulations on the federal and state level. 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 Spectra Energy 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, investments and projects located in Canada expose Spectra Energy to risks related to Canadian laws, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of the Canadian government. From 2002 through 2006, the Canadian dollar has strengthened significantly compared to the U.S. dollar, which has favorably impacted earnings during these periods. Changes in this exchange rate or other of these factors are difficult to predict and may impact future results.
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Certain of Spectra Energy’s earnings are impacted by fluctuations in commodity prices, especially the earnings of the DCP Midstream investment and the Empress NGL operations in Canada. Although natural gas and NGL commodity prices increased in 2005 and 2006, this trend in commodity prices may not be indicative of future prices. Currently, Spectra Energy does not enter into derivative instruments to hedge the expected exposures associated with its processing business in Canada. Prior to 2006, to mitigate the risks associated with its investment in DCP Midstream, Spectra Energy entered into derivative instruments to hedge a portion of these expected exposures. Management evaluates, on an ongoing basis, the level of such hedging and currently does not have any plans to enter into new hedge positions around these earnings.
It is expected that the effective income tax rates will approximate 30-35% on an annual basis, taking into consideration the United States and Canadian tax jurisdictions applicable to operations.
Spectra Energy 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 cash flow from operations. An inability to access capital at competitive rates could adversely affect Spectra Energy’s ability to implement its strategy. Market disruptions, or a downgrade of the credit ratings of Spectra Energy Capital or its subsidiaries may increase the cost of borrowing or adversely affect the ability to access one or more sources of liquidity.
For further information related to management’s assessment of Spectra Energy’s risk factors, see Item 1A. “Risk Factors.”
RESULTS OF OPERATIONS OF SPECTRA ENERGY CAPITAL
Consolidated Operating Revenues
Year Ended December 31, 2006 as Compared to December 31, 2005. Consolidated operating revenues for 2006 decreased $4,922 million, compared to 2005. This change was driven by:
| • | A $5,530 million decrease due to the deconsolidation of DCP Midstream, effective July 1, 2005, and |
| • | An $87 million decrease in captive insurance revenues due to the transfer of ownership in Bison to Duke Energy effective April 1, 2006. |
Partially offsetting this decrease in revenues were:
| • | A $468 million increase at Natural Gas Transmission due primarily to Canadian assets (approximately $281 million), primarily higher processing revenues on the Empress System acquired in August 2005, favorable Canadian dollar foreign exchange impacts (approximately $157 million), and recovery of higher natural gas commodity costs (approximately $146 million), resulting from higher natural gas prices passed through to customers without a mark-up at Union Gas, partially offset by lower gas usage due to unseasonably warmer winter weather (approximately $186 million), and |
| • | An approximate $130 million increase in Other related to the prior year impact of mark-to-market losses, primarily unrealized, due to increased commodity prices as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk (see Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”) from February 22, 2005 to June 30, 2005. Effective with the deconsolidation of DCP Midstream on July 1, 2005, mark-to-market changes related to these discontinued hedges are classified in Other income and expenses, net on the Consolidated Statements of Operations. |
Year Ended December 31, 2005 as Compared to December 31, 2004. Consolidated operating revenues for 2005 decreased $3,979 million, compared to 2004. This change was driven by:
| • | A $5,380 million decrease due to the deconsolidation of DCP Midstream, effective July 1, 2005 |
| • | An approximate $130 million decrease resulting from mark-to-market losses, primarily unrealized, due to increased commodity prices as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk discussed above, and |
| • | An $113 million decrease at Commercial Power due to the sale of the Southeast plants in 2004. |
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Partially offsetting these decreases in revenues were:
| • | An approximate $850 million increase at Field Services, excluding the impact of the deconsolidation of DCP Midstream, due primarily to higher average commodity prices, primarily NGL and natural gas in the first six months of 2005, and |
| • | A $704 million increase at Natural Gas Transmission due primarily to new Canadian assets (approximately $269 million), primarily the Empress System, favorable foreign exchange rates (approximately $153 million) as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses), higher natural gas prices that are passed through to customers (approximately $152 million), an increase related to U.S. business operations (approximately $60 million) driven by higher rates and contracted volumes and increased gas distribution revenues (approximately $36 million), resulting from higher gas usage in the power market |
For a more detailed discussion of operating revenues, see the segment discussions that follow.
Consolidated Operating Expenses
Year Ended December 31, 2006 as Compared to December 31, 2005. Consolidated operating expenses for 2006 decreased $4,789 million, compared to 2005. The change was primarily driven by:
| • | An approximate $5,090 million decrease due to the deconsolidation of DCP Midstream, effective July 1, 2005 |
| • | A $133 million decrease in captive insurance expenses due primarily to the transfer of ownership in Bison to Duke Energy effective April 1, 2006, and prior year recognition of reserves for estimated property damage related to hurricanes and business interruption losses, and |
| • | An approximate $120 million decrease associated with the prior year recognition of unrealized losses in accumulated other comprehensive income (AOCI) as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges (see Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”). |
Partially offsetting these decreases in expenses was:
| • | A $447 million increase at Natural Gas Transmission due primarily to Canadian assets (approximately $189 million), primarily the Empress System, increased natural gas prices at Union Gas (approximately $146 million), resulting from high natural gas prices passed through to customers without a mark-up at Union Gas, higher operating and maintenance, including pipeline integrity and project development expenses (approximately $133 million), Canadian dollar foreign exchange impacts (approximately $124 million), partially offset by lower gas purchase costs at Union Gas resulting primarily from unseasonably warmer winter weather (approximately $157 million). |
Year Ended December 31, 2005 as Compared to December 31, 2004. Consolidated operating expenses for 2005 decreased $3,634 million, compared to 2004. The change was primarily driven by:
| • | A $5,072 million decrease due to the deconsolidation of DCP Midstream, effective July 1, 2005, and |
| • | A $143 million decrease at Commercial Power due to the sale of the Southeast Plants in 2004. |
Partially offsetting these decreases in expenses were:
| • | An approximate $675 million increase in operating expenses at Field Services driven primarily by higher average NGL and natural gas prices in the first six months of 2005 |
| • | A $640 million increase at Natural Gas Transmission due primarily to new Canadian assets (approximately $272 million), primarily gas purchase costs associated with the Empress System, increased natural gas prices at Union Gas (approximately $152 million, which is offset in revenues), foreign exchange impacts (approximately $118 million) as discussed above (offset by currency impacts to revenues), and increased gas purchases for distribution (approximately $43 million) primarily due to higher gas usage in the power market |
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| • | An approximate $120 million increase related to the recognition of unrealized losses in AOCI as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges (see Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”), and |
| • | A $59 million increase as a result of the 2004 correction of an immaterial accounting error in prior periods related to reserves at Bison. |
For a more detailed discussion of operating expenses, see the segment discussions that follow.
Consolidated Gains (Losses) on Sales of Other Assets and Other, net
Consolidated gains (losses) on sales of other assets and other, net was a gain of $47 million for 2006, a gain of $522 million for 2005, and a loss of $349 million for 2004. The gain in 2006 was due primarily to gains on settlements of customers’ transportation contracts at Natural Gas Transmission (approximately $28 million). The gain in 2005 was due primarily to the pre-tax gain resulting from the DCP Midstream disposition transaction (approximately $575 million), partially offset by net pre-tax losses at Commercial Power, principally the termination of former DENA structured power contracts in the Southeast region (approximately $70 million). The loss in 2004 was due primarily to pre-tax losses on the sale of the Southeast Plants (approximately $360 million) at Commercial Power.
Consolidated Operating Income
Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated operating income decreased $608 million, compared to 2005. Decreased operating income was primarily related to an approximate $575 million gain in 2005 resulting from the DCP Midstream disposition transaction and the impacts of the deconsolidation of DCP Midstream, effective July 1, 2005, which amounted to approximately $440 million for 2005. Partially offsetting these decreases were an approximate $250 million negative impact to operating income in 2005 related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk and an approximate $70 million charge in 2005 related to the termination of former DENA structured power contracts in the Southeast region.
Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated operating income increased $526 million, compared to 2004. Increased operating income was due primarily to the gain in 2005 resulting from the DCP Midstream disposition transaction and the charge in 2004 associated with the sale of the Southeast Plants in 2005, partially offset by charges in 2005 related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, charges in 2005 related to the termination of structured power contracts in the Southeast region and increased liabilities associated with mutual insurance companies.
Other drivers to operating income are discussed above. For more detailed discussions, see the segment discussions that follow.
Consolidated Other Income and Expenses
Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated other income and expenses decreased $932 million, compared to 2005. The decrease was due primarily to $1,245 million of pre-tax gains on sales of equity investments recorded in 2005, primarily associated with the sale of TEPPCO GP and Spectra Energy Capital’s limited partner interest in TEPPCO LP, partially offset by an increase of approximately $254 million in equity in earnings of unconsolidated affiliates due primarily to the deconsolidation of DCP Midstream effective July 1, 2005.
Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated other income and expenses increased $1,362 million, compared to 2004. The increase was due primarily to $1,245 million of pre-tax gains associated with the sale of TEPPCO GP and Spectra Energy Capital’s limited partner interest in TEPPCO LP, equity income of $292 million for the investment in DCP Midstream subsequent to the
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deconsolidation of DCP Midstream, effective July 1, 2005, slightly offset by the realized and unrealized pre-tax losses recognized in 2005 on certain derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the deconsolidation of DCP Midstream by Spectra Energy Capital. Effective with the deconsolidation of DCP Midstream on July 1, 2005, mark-to-market changes related to the Field Services discontinued hedges are classified in Other income and expenses, net on the Consolidated Statements of Operations, while from February 22, 2005 to June 30, 2005 these mark-to-market changes were classified in Non-regulated electric, natural gas, natural gas liquids and other revenues on the Consolidated Statements of Operations.
Consolidated Interest Expense
Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated interest expense decreased $70 million, compared to 2005. This decrease is primarily attributable to reduced interest expense associated with DCP Midstream, which was deconsolidated on July 1, 2005 (an approximate $82 million impact).
Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated interest expense decreased $183 million, compared to 2004. This decrease was due primarily to Spectra Energy Capital’s debt reduction in 2004 (an approximate $120 million impact) and the deconsolidation of DCP Midstream effective July 1, 2005 (an approximate $80 million impact).
Consolidated Minority Interest Expense
Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated minority interest expense decreased $466 million, compared to 2005. This decrease primarily resulted from the 2005 gain associated with the sale of TEPPCO GP and the impact of deconsolidation of DCP Midstream effective July 1, 2005.
Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated minority interest expense increased $297 million, compared to 2004. This increase was driven primarily by increased earnings at DCP Midstream in the first six months of 2005 as a result of the sale of TEPPCO GP and higher commodity prices, offset by the impact of the deconsolidation of DCP Midstream effective July 1, 2005.
Consolidated Income Tax Expense from Continuing Operations
Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated income tax expense from continuing operations decreased $531 million, compared to 2005. This decrease primarily resulted from lower pre-tax earnings, due primarily to the 2005 gains associated with the sale of TEPPCO GP and Spectra Energy Capital’s limited partner interest in TEPPCO LP as discussed above. The effective tax rate decreased in 2006 (30%) compared to 2005 (40%). The lower effective tax rate for year ended December 31, 2006 as compared to December 31, 2005 resulted primarily from a $30 million benefit to state taxes due to a reduction in the unitary state tax rate in 2006 as a result of Duke Energy’s merger with Cinergy, a $25 million tax benefit in 2006 related to the impairment of an investment in Bolivia and a $34 million tax expense related to the repatriation of foreign earnings.
Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated income tax expense from continuing operations decreased $342 million, compared to 2004. The decrease in income tax expense from continuing operations is primarily a result of the reorganization of Duke Energy Americas LLC (DEA) in 2004 which caused the recognition of tax expense of approximately $1,030 offset by approximately $2.0 billion in higher pre-tax earnings in 2005, due primarily to the gains associated with the sale of TEPPCO GP, Spectra Energy Capital’s limited partner interest in TEPPCO LP, and the DCP Midstream disposition transaction (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). The effective tax rate for 2005 was 40%, compared to approximately 226% in 2004. The decrease in the effective tax rate was due primarily to the decrease in deferred taxes of approximately $1,030 million related to the restructuring of certain subsidiaries in 2004. (See Note 5 to the Consolidated Financial Statements, “Income Taxes.”)
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Consolidated Income (Loss) from Discontinued Operations, net of tax
Consolidated income (loss) from discontinued operations was $308 million for 2006, ($731) million for 2005, and $593 million for 2004. These amounts represent results of operations and gains (losses) on dispositions related primarily to former DENA’s assets and contracts outside the Midwestern and Southeastern United States, which are included in Other, as well as the operations of International Energy and Spectra Energy Capital’s effective 50% interest in Crescent, and a number of businesses previously included in Other, which are classified in discontinued operations as a result of Spectra Energy Capital transferring these businesses to Duke Energy in December 2006 (see Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). The 2006 amount is primarily comprised of the net favorable operations of International Energy and Spectra Energy Capital’s effective 50% interest in Crescent.
The 2005 amount is primarily comprised of an approximate $740 million non-cash, after-tax charge (approximately $900 million pre-tax) for the impairment of assets, and the discontinuance of hedge accounting and the discontinuance of the normal purchase/normal sale exception for certain positions, as a result of the decision to exit substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Additionally, during 2005, Spectra Energy Capital recognized after-tax losses of approximately $330 million (approximately $400 million pre-tax) as the result of selling certain gas transportation and structured contracts related to the former DENA operations. These charges were offset by the recognition of after-tax gains of approximately $160 million (approximately $200 million pre-tax) related to the recognition of deferred gains in AOCI related to discontinued cash flow hedges related to the former DENA operations and the net favorable operations of International Energy and Spectra Energy Capital’s effective 50% interest in Crescent, and a number of businesses previously included in Other.
The 2004 amount is primarily comprised of a $273 million after-tax gain resulting from the sale of International Energy’s Asia-Pacific Business, and an approximate $180 million after-tax gain on the sale of two partially constructed merchant power plants in the western United States offset by operating losses at the western and northeast merchant power plants and the net favorable operations of International Energy and Spectra Energy Capital’s effective 50% interest in Crescent, and a number of businesses previously included in Other.
Consolidated Cumulative Effect of Change in Accounting Principle, net of tax and minority interest
During 2005, Spectra Energy Capital recorded a net-of-tax and minority interest cumulative effect adjustment for a change in accounting principle of $4 million as a reduction in earnings. The change in accounting principle related to the implementation of FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations,” in which the timing or method of settlement are conditional on a future event that may or may not be within the control of Spectra Energy Capital.
Segment Results
Management evaluates segment performance 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 Spectra Energy Capital, so the gains and losses on foreign currency remeasurement, and interest and dividend 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 Spectra Energy Capital’s ownership interest in operations without regard to financing methods or capital structures.
Effective with the reporting of the 2007 results, and in accordance with SFAS No. 131, “Disclosure About Segments of an Enterprise and Related Information,” Spectra Energy Capital will report financial and operating information on the following four business segments: U.S. Transmission, Distribution, Western Canada Transmission & Processing, and Field Services.
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On April 1, 2006, Spectra Energy Capital transferred the operations of its wholly-owned captive insurance subsidiary, Bison, to Duke Energy. Accordingly, Bison’s operations are not included in Spectra Energy Capital’s results of operations subsequent to its transfer to Duke Energy. Due to continuing involvement between Bison and Spectra Energy Capital entities, the results of operations of Bison do not qualify for discontinued operations treatment.
Additionally, in April 2006, Spectra Energy Capital indirectly transferred to Duke Energy Ohio, its ownership interest in former DENA’s Midwestern assets, representing a mix of combined cycle and peaking plants, with a combined capacity of approximately 3,600 MW. This transfer has been accounted for as a capital contribution at historical cost. An agreement between Spectra Energy Capital and Duke Energy Ohio associated with the transfer was assigned by Spectra Energy Capital to Duke Energy in the fourth quarter of 2006. The results of operations for former DENA’s Midwestern assets have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations.
In December 2006, Spectra Energy Capital transferred the operations of International Energy and Spectra Energy Capital’s effective 50% interest in Crescent, and various other operations previously included in Other to Duke Energy. The results of operations for the majority of these operations have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations. Spectra Energy Capital’s corporate and shared services operations were also transferred to Duke Energy in December 2006. However, as Spectra Energy Capital will have similar types of functions and costs in future periods, substantially all expenses associated with these corporate governance and shared service functions are classified within results from continuing operations in Other for all periods.
As discussed in Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, as well as the transfers of the former DENA Midwestern assets and certain businesses previously included in Other (including DETM), as discussed above, the continuing operations of the former DENA segment, which are now reflected as a component of the Commercial Power segment, include only the Southeastern operations which were disposed of in 2004 and related structured power contracts that were terminated during 2005.
Spectra Energy 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. Segment EBIT is summarized in the following table, and detailed discussions follow.
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EBIT by Business Segment
| Years Ended December 31, | ||||||||||||||||||||
| 2006 | 2005 | Variance 2006 vs 2005 | 2004 | Variance 2005 vs 2004 | ||||||||||||||||
| (in millions) | ||||||||||||||||||||
Natural Gas Transmission | $ | 1,438 | $ | 1,388 | $ | 50 | $ | 1,329 | $ | 59 | ||||||||||
Field Services (a) | 569 | 1,946 | (1,377 | ) | 367 | 1,579 | ||||||||||||||
Commercial Power (b) | — | (70 | ) | 70 | (386 | ) | 316 | |||||||||||||
Total reportable segment EBIT | 2,007 | 3,264 | (1,257 | ) | 1,310 | 1,954 | ||||||||||||||
Other | (89 | ) | (278 | ) | 189 | 48 | (326 | ) | ||||||||||||
Total reportable segment and other EBIT | 1,918 | 2,986 | (1,068 | ) | 1,358 | 1,628 | ||||||||||||||
Interest expense | (605 | ) | (675 | ) | 70 | (858 | ) | 183 | ||||||||||||
Interest income and other (c) | 18 | 24 | (6 | ) | 61 | (37 | ) | |||||||||||||
Consolidated earnings from continuing operations before income taxes | $ | 1,331 | $ | 2,335 | $ | (1,004 | ) | $ | 561 | $ | 1,774 | |||||||||
| (a) | In July 2005, Duke Energy caused a Spectra Energy Capital subsidiary to complete the agreement with ConocoPhillips to reduce Spectra Energy Capital’s ownership interest in DCP Midstream from 69.7% to 50%. Field Services segment data includes DCP Midstream as a consolidated entity for periods prior to July 1, 2005 and an equity method investment for periods after June 30, 2005. |
| (b) | Reflects amounts associated with former DENA’s Southeast operations prior to the sale of the plants in August 2004 and the sale of the structured power contracts in December 2005. |
| (c) | Other includes foreign currency transaction gains and losses and additional minority interest expense not allocated to the segment results. |
Minority interest expense as shown and discussed below includes only minority interest expense related to EBIT of Spectra Energy Capital’s joint ventures. It does not include minority interest expense related to interest and taxes of the joint ventures.
The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements.
Natural Gas Transmission
| Years Ended December 31, | |||||||||||||||||
| 2006 | 2005 | Variance 2006 vs 2005 | 2004 | Variance 2005 vs 2004 | |||||||||||||
| (in millions, except where noted) | |||||||||||||||||
Operating revenues | $ | 4,523 | $ | 4,055 | $ | 468 | $ | 3,351 | $ | 704 | |||||||
Operating expenses | 3,162 | 2,715 | 447 | 2,075 | 640 | ||||||||||||
Gains (losses) on sales of other assets and other, net | 47 | 13 | 34 | 17 | (4 | ) | |||||||||||
Operating income | 1,408 | 1,353 | 55 | 1,293 | 60 | ||||||||||||
Other income and expenses, net | 69 | 65 | 4 | 63 | 2 | ||||||||||||
Minority interest expense | 39 | 30 | 9 | 27 | 3 | ||||||||||||
EBIT | $ | 1,438 | $ | 1,388 | $ | 50 | $ | 1,329 | $ | 59 | |||||||
Proportional throughput, TBtu (a) | 3,248 | 3,410 | (162 | ) | 3,332 | 78 | |||||||||||
| (a) | Trillion British thermal units. Revenues are not significantly impacted by pipeline throughput fluctuations since revenues are primarily composed of demand charges. |
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Year Ended December 31, 2006 as Compared to December 31, 2005
Operating Revenues. The increase was driven primarily by:
| • | A $281 million increase due to Canadian assets purchased in August 2005, primarily higher processing revenues on the Empress System as a result of commodity prices, |
| • | A $157 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 $146 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices passed through to customers without a mark-up at Union Gas. This revenue increase is offset in expenses, |
| • | A $27 million increase in U.S. business operations driven by increased processing revenues associated with transportation, and |
| • | A $26 million increase from completed and operational pipeline expansion projects in the U.S. |
Partially offsetting these increases was:
| • | A $186 million decrease in gas distribution revenues at Union Gas primarily resulting from lower gas usage due to warmer winter weather compared to 2005. |
Operating Expenses. The increase was driven primarily by:
| • | A $189 million increase in gas purchase cost associated with the Empress System, |
| • | A $146 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues. |
| • | A $133 million increase primarily related to increased operating and maintenance expenses on pipeline and storage operations, including pipeline integrity and project development expenses, higher insurance premiums, and benefit costs, and |
| • | A $124 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above). |
Partially offsetting these increases were:
| • | A $157 million decrease in gas purchase costs at Union Gas, primarily resulting from lower gas usage due to unseasonably warmer winter weather, and |
| • | A $15 million decrease related to the resolution in 2006 of prior tax years’ ad valorem tax issues. |
Gains (Losses) on Sales of Other Assets and Other, net. The increase was driven primarily by a $28 million gain in 2006 on the settlement of a customer’s transportation contract, and a $5 million gain on the sale of Stone Mountain assets in 2006.
Other Income and Expenses, net. The increase was driven primarily by a pre-tax Staff Accounting Bulletin (SAB) No. 51 gain of $15 million related to the Income Fund’s issuance of additional units of the Canadian income trust fund, partially offset by a construction fee received in 2005 from an affiliate as a result of the successful completion of the Gulfstream Natural Gas System, LLC (Gulfstream), 50% owned by Spectra Energy Capital, and Natural Gas Transmission’s 50% share of operating and maintenance expenses in 2006 on the Southeast Supply Header project.
EBIT. The increase in EBIT is due primarily to the increase in processing earnings (primarily Empress System), the gain on settlement of a customer’s transportation contract, U.S. business expansion, the gain on the Income Fund’s issuance of additional units of the Canadian income trust fund, a gain on a property insurance settlement and the strengthening Canadian dollar, partially offset by increased operating and maintenance expenses, and lower Union results primarily due to weather.
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Matters Impacting Future Natural Gas Transmission Results
As previously discussed, Spectra Energy and Spectra Energy Capital have implemented new business segment reporting in 2007. Amounts previously reported for Spectra Energy Capital’s Natural Gas Transmission segment will primarily be reported in the new U.S. Transmission, Distribution and Western Canada Transmission & Processing segments. The following discusses matters impacting future results of these new segments.
U.S. Transmission plans to continue earnings growth through capital efficient projects, such as transportation and storage expansion to support a two-pronged “supply push” / “market pull” strategy, as well as continued focus on optimizing the performance of the existing operations through organizational efficiencies and cost control. Future earnings growth will be dependent on the success of expansion plans in both the market and supply areas of the pipeline network, the ability to continue renewing service contracts and continued regulatory stability. Commodity prices will continue to impact processing revenues that are associated with transportation services.
Distribution plans to continue earnings growth through capital efficient “market pull” expansion projects of transportation and storage capacity to support the projected demand growth in the Ontario market. The projected natural gas demand in Ontario benefits the continued retail distribution growth as well. Distribution’s earnings are impacted significantly by weather during the winter heating season. In addition, earnings over the last several years have benefited from the strengthening Canadian dollar and would be impacted by future changes in the US/Canadian dollar exchange rates. As with all of Spectra Energy Capital’s regulated entities, regulatory changes may impact future earnings.
Western Canada Transmission & Processing plans to continue earnings growth through capital efficient “supply push” projects, primarily associated with gathering and processing expansion to support drilling activity in northern British Columbia. Earnings will also continue to improve through optimizing the performance of the existing system and through organizational efficiencies. In addition, future earnings will be impacted by the ability to renew service contracts and regulatory stability. Earnings from processing services will be impacted by the ability to access additional natural gas reserves. In addition, the Empress NGL business will be impacted by both gas flows and the effects of natural gas and NGL commodity prices. On October 31, 2006, the Minister of Finance in Canada announced proposed changes to the income tax treatment of “flow-through entities,” including income trusts, such as the Income Fund, in which the Western Canada Transmission & Processing segment owns approximately 46% as of December 2006. If the proposal is implemented in its current form, income trusts will be subject to tax at corporate rates on the taxable portion of their distributions which would apply beginning with the 2011 taxation year of the Income Fund. On December 15, 2006, the Department of Finance of Canada provided further guidance on “normal growth” for flow-through entities. The guidance limits the amount of new equity that can be issued if the Income Fund wishes to retain its current tax status until 2011. The guidance indicates, subject to annual limits, that the Income Fund can issue up to Canadian $296 million of new equity prior to December 31, 2010 without losing its current tax status. The legislation is still in draft form and is subject to continuing debate. The implementation of the legislation could have an adverse effect on the Income Fund, its ability to pay distributions and the market value of its units. Spectra Energy Capital will monitor the impact of these proposed changes on the Income Fund and on the future use of such entities, but does not currently expect significant impacts to Spectra Energy Capital as a result of these changes.
Year Ended December 31, 2005 as Compared to December 31, 2004
Operating Revenues. The increase was driven primarily by:
| • | A $269 million increase due to new Canadian assets, primarily the Empress System |
| • | A $153 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 $152 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. This revenues increase is offset in expenses |
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| • | A $60 million increase for U.S. business operations driven by higher rates at Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively, M & N Pipeline) and favorable commodity prices on natural gas processing activities |
| • | A $36 million increase in gas distribution revenues, primarily due to higher gas usage in the power market, and |
| • | A $20 million increase from completed and operational pipeline expansion projects in the U.S. |
Operating Expenses. The increase was driven primarily by:
| • | A $272 million increase due to new Canadian assets, primarily gas purchase costs associated with the Empress System |
| • | A $152 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues |
| • | A $118 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above) |
| • | A $43 million increase in gas purchases for distribution, primarily due to higher gas usage in the power market, and |
| • | A $23 million increase related to the 2004 resolution of ad valorem tax issues in various states. |
Other Income and Expenses, net. The increase was driven primarily by the successful completion of the Gulfstream Phase II project which went into service in February 2005 and increased volumes at Gulfstream, resulting in a $11 million increase in Gas Transmission’s 50% equity earnings and a $5 million construction fee received from an affiliate. These increases were partially offset by a $16 million gain in 2004 on the sale of equity investments, primarily due to the resolution of contingencies related to the sales price of those investments.
EBIT. The increase in EBIT was due primarily to earnings from U.S. business expansion projects, improved U.S. operations and favorable foreign exchange rate impacts from the strengthening Canadian dollar, partially offset by the 2004 resolution of ad valorem tax issues.
Field Services
| Years Ended December 31, | ||||||||||||||||||
| 2006 | 2005 | Variance 2006 vs 2005 | 2004 | Variance 2005 vs 2004 | ||||||||||||||
| (in millions, except where noted) | ||||||||||||||||||
Operating revenues | $ | — | $ | 5,530 | $ | (5,530 | ) | $ | 10,044 | $ | (4,514 | ) | ||||||
Operating expenses | 5 | 5,215 | (5,210 | ) | 9,489 | (4,274 | ) | |||||||||||
Gains (losses) on sales of other assets and other, net | — | 577 | (577 | ) | 2 | 575 | ||||||||||||
Operating income | (5 | ) | 892 | (897 | ) | 557 | 335 | |||||||||||
Equity in earnings of unconsolidated affiliates (a) | 574 | 292 | 282 | — | 292 | |||||||||||||
Other income and expenses, net | — | 1,259 | (1,259 | ) | 37 | 1,222 | ||||||||||||
Minority interest expense | — | 497 | (497 | ) | 227 | 270 | ||||||||||||
EBIT | $ | 569 | $ | 1,946 | $ | (1,377 | ) | $ | 367 | $ | 1,579 | |||||||
Natural gas gathered and processed/transported, TBtu/d (b) | 6.8 | 6.8 | — | 6.8 | — | |||||||||||||
NGL production, MBbl/d (c) | 361 | 353 | 8 | 356 | (3 | ) | ||||||||||||
Average natural gas price per MMBtu (d) | $ | 7.23 | $ | 8.59 | $ | (1.36 | ) | $ | 6.14 | $ | 2.45 | |||||||
Average NGL price per gallon (e) | $ | 0.94 | $ | 0.85 | $ | 0.09 | $ | 0.68 | $ | 0.17 | ||||||||
| (a) | Includes Spectra Energy Capital’s 50% equity in earnings of DCP Midstream net income subsequent to the deconsolidation of DCP Midstream effective July 1, 2005. Results of DCP Midstream prior to July 1, 2005 are presented on a consolidated basis. |
| (b) | Trillion British thermal units per day |
| (c) | Thousand barrels per day |
| (d) | Million British thermal units. Average price based on NYMEX Henry Hub |
| (e) | Does not reflect results of commodity hedges |
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In July 2005, Duke Energy caused a Spectra Energy Capital subsidiary to complete the transfer of a 19.7% interest in DCP Midstream to ConocoPhillips, Spectra Energy Capital’s co-equity owner in DCP Midstream, which reduced Spectra Energy Capital’s ownership interest in DCP Midstream from 69.7% to 50% and resulted in Spectra Energy Capital and ConocoPhillips becoming equal 50% owners in DCP Midstream. As a result of the DCP Midstream disposition transaction, Spectra Energy Capital deconsolidated its investment in DCP Midstream and subsequently has accounted for DCP Midstream as an investment utilizing the equity method of accounting (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).
Year Ended December 31, 2006 as Compared to December 31, 2005
Operating Revenues. The decrease was due to the DCP Midstream disposition transaction and subsequent deconsolidation of DCP Midstream.
Operating Expenses. The decrease was due to the DCP Midstream disposition transaction and subsequent deconsolidation of DCP Midstream. Operating expenses for 2005 were also impacted by approximately $120 million of losses recognized due to the reclassification of pre-tax unrealized losses in AOCI as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges.
Gains (Losses) on Sales of Other Assets and Other, net. The decrease was due primarily to an approximate pre-tax gain of $575 million on the DCP Midstream disposition transaction in the prior year.
Equity in Earnings of Unconsolidated Affiliates. The increase is due to Spectra Energy Capital’s 50% of equity in earnings of DCP Midstream’ net income for the twelve months ended December 31, 2006 as compared to equity in earnings of DCP Midstream’ net income for the six months ended December 31, 2005. DCP Midstream’ earnings during the twelve months ended December 31, 2006 have continued to be favorably impacted by increased NGL and crude oil prices as compared to the prior period, as well as increased trading and marketing gains due primarily to changes in natural gas prices and the timing of derivative and inventory transactions.
Other Income and Expenses, net. The decrease is due to the DCP Midstream disposition transaction and subsequent deconsolidation of DCP Midstream. In 2005, DCP Midstream had a pre-tax gain on the sale of its wholly-owned subsidiary, TEPPCO GP, the general partner of TEPPCO LP of $1.1 billion, and Spectra Energy Capital had a pre-tax gain on the sale of its limited partner interest in TEPPCO LP of approximately $97 million. TEPPCO GP and Spectra Energy Capital’s limited partner interest in TEPPCO LP were each sold to Enterprise GP Holdings LP, an unrelated third party.
Minority Interest Expense. The decrease was due to the DCP Midstream disposition transaction and subsequent deconsolidation of DCP Midstream. Minority interest expense for 2005 was due primarily to the gain on the sale of TEPPCO GP to Enterprise GP Holdings LP for approximately $1.1 billion, as discussed above.
EBIT. The decrease in EBIT from 2006 to 2005 resulted primarily from the gain on sale of TEPPCO GP and Spectra Energy Capital’s limited partner interest in TEPPCO LP in 2005 and gain on the DCP Midstream disposition transaction in 2005. These decreases were partially offset by increased NGL and crude oil prices in 2006 as compared to the prior year.
Matters Impacting Future Field Services Results
Field Services, through its 50% investment in DCP Midstream, has developed significant size and scope in natural gas gathering, processing and NGL marketing and plans to focus on operational excellence and organic growth. DCP Midstream’s 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. DCP Midstream 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 DCP Midstream’s business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production. Future equity in earnings of DCP
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Midstream will continue to be sensitive to commodity prices that have historically been cyclical and volatile. 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, 2005 as Compared to December 31, 2004
Operating Revenues. The decrease was due to the DCP Midstream disposition transaction and subsequent deconsolidation of DCP Midstream. This decrease was partially offset by increased revenues of approximately $850 million during the six months ended June 30, 2005 versus the comparable period in the prior year which was primarily attributable to a $0.14 per gallon increase in average NGL prices and a $0.66 per MMBtu increase in average natural gas prices.
Operating Expenses. The decrease was due to the DCP Midstream disposition transaction and subsequent deconsolidation of DCP Midstream. Subsequent to June 2005, the results of DCP Midstream are included in Equity in Earnings of Unconsolidated Affiliates. This decrease was partially offset by:
| • | Increased operating expense of approximately $675 million during the six months ended June 30, 2005 versus the comparable period in the prior year which was primarily attributable to higher average costs of raw natural gas supply, due primarily to an increase in average NGL and natural gas prices, and |
| • | An approximate $120 million increase due to the reclassification of pre-tax unrealized losses in AOCI in 2005 as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges (see Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”). After the discontinuance of these hedges, changes in their fair value are being recognized in Other results, as management considers the discontinuance to be an event which disassociates the contracts from the Field Services’ results. |
Gains (Losses) on Sales of Other Assets and Other, net. The increase was primarily due to an approximate pre-tax gain of $575 million on the DCP Midstream disposition transaction.
Equity in Earnings of Unconsolidated Affiliates. The increase was driven by the equity in earnings of $292 million for Spectra Energy Capital’s investment in DCP Midstream subsequent to the completion of the DCP Midstream disposition transaction and related deconsolidation. DCP Midstream earnings during the six months ended December 31, 2005 have continued to be favorably impacted by increased commodity prices. These increases were partially offset by higher operating costs and pipeline integrity work as well as lower volumes due in part to hurricane interruptions.
Other Income and Expenses, net. The increase was driven primarily by an approximate $1.1 billion pre-tax gain in 2005 on the sale of DCP Midstream’ wholly-owned subsidiary, TEPPCO GP, the general partner of TEPPCO LP, and the pre-tax gain on the sale of Spectra Energy Capital’s limited partner interest in TEPPCO LP of approximately $100 million. TEPPCO GP and Spectra Energy Capital’s limited partner interest in TEPPCO LP were each sold to Enterprise GP Holdings LP, an unrelated third party. The gain was partially offset by a $33 million decrease in earnings from equity method investments, primarily as a result of the sale of TEPPCO GP and Spectra Energy Capital’s limited partner interest in TEPPCO LP in the first quarter of 2005.
Minority Interest Expense. The increase was due primarily to the minority interest impact of the gain on the sale of TEPPCO GP to Enterprise GP Holdings LP as well as increased earnings at DCP Midstream during the six months ended June 30, 2005 due to commodity price increases. This increase was partially offset by the DCP Midstream disposition transaction and the related deconsolidation of Spectra Energy Capital’s investment in DCP Midstream.
EBIT. The increase was primarily driven by the gain on sale of TEPPCO GP and Spectra Energy Capital’s limited partner interest in TEPPCO LP, the gain as a result of the DCP Midstream disposition transaction and favorable effects of commodity price increases, partially offset by the impact of Spectra Energy Capital’s decreased ownership percentage resulting from the completion of the DCP Midstream disposition transaction. Also, in the first quarter of 2005, Spectra Energy Capital discontinued certain cash flow hedges entered into to
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hedge Field Services’ commodity price risk (see Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”). As a result of the discontinuance of these cash flow hedges and hedge accounting treatment, approximately $120 million of pre-tax unrealized losses in AOCI related to these contracts have been recognized by Field Services during the year ended December 31, 2005. Field Services’ future results are subject to volatility for factors such as commodity price changes.
Supplemental Data
Below is supplemental information for DCP Midstream operating results subsequent to deconsolidation on July 1, 2005:
| Twelve Months Ended December 31, 2006 | Six Months Ended December 31, 2005 | |||||
| (in millions) | ||||||
Operating revenues | $ | 12,335 | $ | 7,463 | ||
Operating expenses | 11,063 | 6,814 | ||||
Operating income | 1,272 | 649 | ||||
Other income and expenses, net | 5 | 1 | ||||
Interest expense, net | 119 | 62 | ||||
Income tax expense | 23 | 4 | ||||
Net income | $ | 1,135 | $ | 584 | ||
Commercial Power
| Years Ended December 31, | ||||||||||||||||||
| 2006 | 2005 | Variance 2006 vs 2005 | 2004 | Variance 2005 vs 2004 | ||||||||||||||
| (in millions) | ||||||||||||||||||
Operating revenues | $ | — | $ | — | $ | — | $ | 113 | $ | (113 | ) | |||||||
Operating expenses | — | — | — | 143 | (143 | ) | ||||||||||||
Gains (losses) on sales of other assets and other, net | — | (70 | ) | 70 | (359 | ) | 289 | |||||||||||
Operating income | — | (70 | ) | 70 | (389 | ) | 319 | |||||||||||
Other income and expenses, net | — | — | — | 3 | (3 | ) | ||||||||||||
EBIT | $ | — | $ | (70 | ) | $ | 70 | $ | (386 | ) | $ | 316 | ||||||
Commercial Power includes the historical results of the remaining Southeastern operations related to the assets which were disposed of in 2004 and the sale of the structured power contracts in 2005, but are not included in discontinued operations due to continuing involvement (see Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale.”)
Year Ended December 31, 2006 as compared to December 31, 2005
Gain (losses) on Sales of Other Assets and Other, net. The increase was driven primarily by an approximate $70 million pre-tax charge in 2005 related to the termination of structured power contracts in the Southeastern Region.
EBIT. The increase was due to the approximate $70 million pre-tax charge in 2005 related to the termination of structured power contracts in the Southeastern Region.
Year Ended December 31, 2005 as compared to December 31, 2004
Operating Revenues. The decrease was due to the sale of the Southeast plants in 2004.
Operating Expenses. The decrease was due to the sale of the Southeast plants in 2004.
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Gains (losses) on sales of other assets and other, net. The 2005 loss was due primarily to an approximate $70 million pre-tax charge related to the termination of structured power contracts in the Southeastern Region. The 2004 results include pre-tax losses of approximately $360 million associated with the sale of the Southeast Plants.
EBIT. EBIT loss decreased driven by the loss recognized in 2004 on the sale of the Southeast Plants.
Other
| Years Ended December 31, | ||||||||||||||||||||
| 2006 | 2005 | Variance 2006 vs 2005 | 2004 | Variance 2005 vs 2004 | ||||||||||||||||
| (in millions) | ||||||||||||||||||||
Operating revenues | $ | 30 | $ | (4 | ) | $ | 34 | $ | 111 | $ | (115 | ) | ||||||||
Operating expenses | 182 | 303 | (121 | ) | 222 | 81 | ||||||||||||||
Gains (losses) on sales of other assets and other, net | — | 4 | (4 | ) | (8 | ) | 12 | |||||||||||||
Operating income | (152 | ) | (303 | ) | 151 | (119 | ) | (184 | ) | |||||||||||
Other income and expenses, net | 63 | 25 | 38 | 167 | (142 | ) | ||||||||||||||
EBIT | $ | (89 | ) | $ | (278 | ) | $ | 189 | $ | 48 | $ | (326 | ) | |||||||
Year Ended December 31, 2006 as Compared to December 31, 2005
Operating Revenues. The increase was driven primarily by:
| • | An approximate $130 million increase as a result of the prior year impact of realized and unrealized mark-to-market losses on certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk which were accounted for as Operating Revenues prior to the deconsolidation of DCP Midstream, effective July 1, 2005. |
Partially offsetting this increase were:
| • | An $87 million decrease in captive insurance revenues due to the transfer of ownership in Bison to Duke Energy effective April 1, 2006, and |
| • | A $21 million decrease due to a prior year mark-to-market gain related to former DENA’s hedge discontinuance in the Southeast. |
Operating Expenses. The decrease was driven primarily by:
| • | A $133 million decrease in captive insurance expenses due primarily to the transfer of ownership in Bison to Duke Energy effective April 1, 2006, and prior year recognition of reserves for estimated property damage related to hurricanes and business interruption losses. |
Partially offsetting this decreases was:
| • | A $13 million increase primarily associated with Duke Capital’s proportionate share of Duke Energy’s costs to achieve the Cinergy merger in 2006. |
Other Income and Expenses, net. The increase was driven primarily by an approximate $45 million favorable variance resulting from the realized and unrealized mark-to-market impacts associated with certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk which are recorded in Other income and expenses, net on the Consolidated Statements of Operations subsequent to the deconsolidation of DCP Midstream, effective July 1, 2005. Other income and expenses, net includes $82 million and $68 million in 2006 and 2005, respectively, related to management fees charged to an unconsolidated affiliate.
EBIT. The increase was due primarily to the favorable variance related to realized and unrealized mark-to-market impacts of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk and prior year recognition of reserves for estimated property damage related to hurricanes and business interruption, partially offset by the prior year mark-to-market gain related to former DENA hedge discontinuance in the Southeast.
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Matters Impacting Future Other Results
Future Other results will include corporate and business services provided for the operations of Spectra Energy, and will also include costs and losses associated with Spectra Energy Capital’s new captive insurance company.
As a result of the separation from Duke Energy, Spectra Energy, primarily through Spectra Energy Capital, has newly staffed various corporate and other support functions, such as treasury, tax, cash management, payroll, accounts payable, information technology, human resources, and legal and compliance that will be required to operate as a stand-alone public company. Primarily during the first year following the separation date, it is expected that Duke Energy will provide certain transition services to Spectra Energy until such time as Spectra Energy can create all of the necessary stand-alone functions. The Duke Energy corporate costs included in Spectra Energy Capital’s historical financial statements will be replaced by Spectra Energy’s independent operating costs, including the new corporate functions, and will also include transition service fees paid to Duke Energy pursuant to the transition service arrangements that are expected to occur primarily in 2007. The amount of fees expected to be paid to Duke Energy in 2007 is approximately $10 million, but could vary depending on the ultimate usage and level of services required. Future corporate costs of Spectra Energy Capital are expected to be significantly less than the historical level of such costs given that the historical corporate services were structured to provide services to all of Spectra Energy Capital’s previous business groups, including International Energy, Crescent, DENA and DETM. In addition, Spectra Energy Capital has discontinued providing management services to the Duke Energy affiliate, and as such, will no longer realize the associated management fee income.
In 2007, Other will include costs associated with the spin-off, such as costs for branding the new company, replacing signage, creating new investor and other stakeholder communication processes and costs for building and/or reconfiguring the required information systems primarily around financial systems. The spin-off costs expected to affect the operating results of Other will approximate $50 million in 2007 and are not expected to be material thereafter.
Year Ended December 31, 2005 as Compared to December 31, 2004
Operating Revenues. The decrease was driven primarily by:
| • | An approximate $130 million decrease as a result of the realized and unrealized mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk (see Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”). |
Partially offsetting this decrease was:
| • | A $21 million mark-to-market gain in 2005 related to former DENA’s hedge discontinuance in the Southeast. |
Operating Expenses. The increase was driven primarily by:
| • | A $59 million increase as a result of the 2004 correction of an immaterial accounting error in prior periods related to reserves at Bison attributable to property losses at several Spectra Energy Capital subsidiaries, and |
| • | A $19 million increase as a result of increased liabilities associated with mutual insurance companies. |
Gains (Losses) on Sales of Other Assets and Other, net. The 2004 loss was due primarily to a loss on the sale of an aircraft.
Other Income and Expenses, net. The decrease was driven primarily by an $83 million decrease in a management fees charged to an unconsolidated affiliate and an approximate $64 million decrease as a result of the realized and unrealized mark-to-market impact on discontinued hedges related to Field Services’ commodity price risk. (See Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)
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EBIT. The decrease was due primarily to the realized and unrealized mark-to-market impacts of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk, the reversal of insurance reserves at Bison in 2004 and a decrease in management fees charged to an unconsolidated affiliate. These decreases were partially offset by the mark-to-market gain in 2005 related to former DENA’s hedge discontinuance in the Southeast.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The application of accounting policies and estimates is an important process that continues to evolve as Spectra Energy Capital’s operations change and accounting guidance evolves. Spectra Energy 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 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. Spectra Energy Capital discusses its critical accounting policies and estimates and other significant accounting policies with senior members of management. Spectra Energy Capital’s critical accounting policies and estimates are discussed below.
Regulatory Accounting
Spectra Energy Capital accounts for certain of its regulated operations under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, Spectra Energy 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 costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that either are not likely to or have yet to be incurred. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities. 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, asset write-offs would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of property, plant and equipment and amortization of regulatory assets. Total regulatory assets were $959 million as of December 31, 2006 and $1,063 million as of December 31, 2005. Total regulatory liabilities were $569 million as of December 31, 2006 and $420 million as of December 31, 2005. (See Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”)
Long-Lived Asset Impairments and Assets Held For Sale
Spectra Energy 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, 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.
Spectra Energy 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 both the sales of power and the natural gas fuel costs 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.
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A change in Spectra Energy Capital’s plans regarding, or probability assessments of, holding or selling an asset could have a significant impact on the estimated future cash flows. Spectra Energy 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, “Accounting for the Impairment or Disposal of Long-Lived Assets.” (SFAS No. 144)
During 2006 and 2005, Spectra Energy Capital recorded impairments on several of its long-lived assets. (For discussion of these impairments, see Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held For Sale.”)
Spectra Energy Capital uses the criteria in SFAS No. 144 and EITF 03-13, “Applying the Conditions in Paragraph 42 of SFAS No. 144 in Determining Whether to Report Discontinued Operations,” to determine whether components of Spectra Energy Capital that are being disposed of or are classified as held for sale are required to be reported as discontinued operations in the Consolidated Statements of Operations. To qualify as a discontinued operation under SFAS No. 144, the component being disposed of must have clearly distinguishable operations and cash flows. Additionally, pursuant to EITF 03-13, Spectra Energy Capital must not have significant continuing involvement in the operations after the disposal (i.e. Spectra Energy Capital must not have the ability to influence the operating or financial policies of the disposed component) and cash flows of the assets sold must have been eliminated from Spectra Energy Capital’s ongoing operations (i.e. Spectra Energy Capital does not expect to generate significant direct cash flows from activities involving the disposed component after the disposal transaction is completed). Assuming both preceding conditions are met, the related results of operations for the current and prior periods, including any related impairments and gains or losses on sales, are reflected as Income (Loss) From Discontinued Operations, net of tax, in the Consolidated Statements of Operations. If an asset held for sale does not meet the requirements for discontinued operations classification, any impairments and gains or losses on sales are recorded in continuing operations as Gains (Losses) on Sales of Other Assets and Other, net, in the Consolidated Statements of Operations. Impairments for all other long-lived assets, other than goodwill, are recorded as Impairments and other charges in the Consolidated Statements of Operations.
Impairment of Goodwill
At December 31, 2006 and 2005, Spectra Energy Capital had goodwill balances of $3,507 million and $3,775 million, respectively. Spectra Energy Capital evaluates the impairment of goodwill under SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). The majority of Spectra Energy Capital’s goodwill at December 31, 2006 relates to the acquisition of Westcoast Energy, Inc. (Westcoast) in March 2002, whose assets are primarily included within the Natural Gas Transmission segment. As of the acquisition date, Spectra Energy Capital allocates goodwill to a reporting unit, which Spectra Energy Capital defines as an operating segment or one level below an operating segment. As required by SFAS No. 142, Spectra Energy 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 and estimated future cash flows. In estimating cash
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flows, Spectra Energy Capital incorporates expected growth rates, regulatory stability, ability to renew contracts, and foreign currency exchange rates, as well as other factors that affect its revenue and expense forecasts. As a result of the annual 2006 impairment test required by SFAS No. 142, Spectra Energy Capital did not record any impairment on its goodwill during 2006, 2005 or 2004.
As noted previously, the business segments of Spectra Energy Capital were revised early in 2007 as a result of the separation from Duke Energy, impacting the reporting units used for goodwill impairment reviews. This change to the reporting unit designations has not resulted in any impairments of Spectra Energy Capital’s goodwill. 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.
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 (prior to deconsolidation), 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. Differences between actual and estimated unbilled revenues are immaterial.
LIQUIDITY AND CAPITAL RESOURCES
Known Trends and Uncertainties
Spectra Energy will rely primarily upon cash flows from operations and additional financing transactions of Spectra Energy Capital to fund its liquidity and capital requirements for 2007. As of December 31, 2006, Spectra Energy Capital had negative working capital of approximately $730 million. This balance includes short-term debt of $349 million and current maturities of long-term debt of $550 million which are due primarily in July 2007 and December 2007 and are expected to be financed through additional long-term borrowings. In addition to the issuance of short-term debt and new long-term debt issuances expected during 2007, Spectra Energy expects to complete an MLP transaction during mid-2007 which could provide net cash proceeds of approximately $300 million to $400 million. See further discussion in Financing Cash Flows. Spectra Energy Capital also has access to four revolving credit facilities available in two currencies, with total combined capacities of $950 million and Canadian $600 million. These facilities will be used principally as a back-stop for commercial paper programs at Spectra Energy Capital subsidiaries.
Ultimate cash flows from operations are subject to a number of factors, including, but not limited to, earnings sensitivities to weather, commodity prices, and the timing of associated regulatory cost recovery approval (see “Item 1A. Risk Factors” for details). As discussed further in Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies,” Spectra Energy Capital entered into a settlement agreement and paid approximately $100 million to resolve pending litigation associated with the Citrus Trading matter. Spectra Energy Capital recorded the $100 million charge in the fourth quarter of 2006 within discontinued operations.
Spectra Energy Capital projects 2007 capital and investment expenditures of approximately $1.6 billion, consisting of $0.8 billion for U.S. Transmission, $0.5 billion for Western Canada Transmission & Processing, and $0.3 billion for Distribution. Total projected 2007 capital and investment expenditures include approximately $1.1 billion of expansion capital expenditures and approximately $0.5 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth.
As Spectra Energy Capital executes on its strategic objectives around organic growth and expansion projects, capital and investment expenditures could average approximately $1.5 billion per year over the next several years. The timing and extent of these projects are likely to vary significantly from year to year, however. Given the anticipated levels of ongoing capital and investment expenditures over the next several years, capital resources will likely include additional long-term borrowings as well as the utilization of financial structures such as MLPs. However, Spectra Energy Capital expects to maintain a capital structure and liquidity profile that continues to support an investment-grade credit rating.
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Spectra Energy 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. Spectra Capital also maintains an active dialogue with the credit rating agencies, and believes that the current investment grade credit ratings are stable.
Operating Cash Flows
Net cash provided by operating activities was $693 million in 2006 compared to $1,072 million in 2005, a decrease of $379 million. The decrease in cash provided by operating activities was due primarily to the following:
| • | An approximate $400 million decrease in 2006 due to the net settlement of remaining DENA contracts |
| • | Collateral received by Spectra Energy Capital (approximately $540 million) in 2006 from Barclays, partially offset by |
| • | The settlement of the payable to Barclays (approximately $600 million) in 2006 |
Net cash provided by operating activities was $1,072 million in 2005 compared to $2,237 million in 2004, a decrease of $1,165 million. The decrease in cash provided by operating activities was due primarily to the following:
| • | Approximately $800 million of additional net cash collateral posted by Spectra Energy Capital during 2005 attributable to increased crude prices, as well as increases to the forward market prices of power |
| • | An approximate $900 million increase in taxes paid, and |
| • | The impacts of the deconsolidation of DCP Midstream effective July 1, 2005. |
Investing Cash Flows
Net cash provided by investing activities was $1,569 million in 2006 compared to $1,241 million in 2005, an increase in cash provided of $328 million. Net cash provided by investing activities was $1,241 million in 2005 compared to $760 million in 2004, an increase in cash provided of $481 million.
The increase in cash provided by investing activities in 2006 as compared to 2005 is primarily due to the following:
| • | An approximate $700 million increase in cash provided by proceeds from sales and maturities of marketable securities, net of purchases of marketable securities, and |
| • | A decrease in cash used for acquisitions of approximately $200 million, as a result of the approximately $230 million 2005 acquisition of the Empress System at Natural Gas Transmission. |
These increases were partially offset by the following:
| • | A decrease in proceeds received from asset sales in 2006 as compared to 2005. Asset sales activity in 2006 of approximately $2.0 billion primarily involved the disposal of the former DENA operations outside of the Midwestern United States, as well as the Crescent JV transaction. Asset sales activity in 2005 of approximately $2.4 billion primarily involved the disposition of the investments in TEPPCO as well as the DCP Midstream disposition transaction. |
| • | $152 million of distributions from equity investees were considered returns of equity in 2006 (primarily DCP Midstream), as compared to $383 million (see below) in 2005. |
The increase in cash provided by investing activities in 2005 as compared to 2004 was also impacted by the following:
| • | Proceeds from the 2005 sale of TEPPCO GP and Spectra Energy Capital’s interest in TEPPCO LP for approximately $1.2 billion, |
| • | DCP Midstream disposition transaction proceeds of approximately $1.0 billion received in 2005, |
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| • | $383 million of distributions from equity investees (approximately $310 million for Gulfstream and approximately $73 million for DCP Midstream) were considered returns of equity in 2005, and |
| • | Decreased amounts of cash invested in short-term investments in 2005 as compared to 2004. |
These increases were partially offset by:
| • | The approximate $1.6 billion in proceeds received in 2004 primarily from the sales of the Asia-Pacific Business, Southeast Plants and Moapa and Luna partially completed facilities. |
Capital and Investment Expenditures by Business Segment
Capital and investment expenditures are detailed by business segment in the following table. Capital and investment expenditures presented below include expenditures from both continuing and discontinued operations.
| Years Ended December 31, | |||||||||
| 2006 | 2005 | 2004 | |||||||
| (in millions) | |||||||||
Natural Gas Transmission | $ | 790 | $ | 930 | $ | 544 | |||
Field Services (a) | — | 86 | 202 | ||||||
International Energy | 58 | 23 | 28 | ||||||
Crescent (b)(c) | 507 | 599 | 568 | ||||||
Other | 130 | 31 | 40 | ||||||
Total consolidated | $ | 1,485 | $ | 1,669 | $ | 1,382 | |||
| (a) | As a result of the deconsolidation of DCP Midstream, effective July 1, 2005, Field Services amounts only include DCP Midstream capital and investment expenditures for periods prior to July 1, 2005. |
| (b) | Amounts include capital expenditures associated with residential real estate of $322 million for the period from January 1, 2006 through the date of deconsolidation (September 7, 2006), $355 million in 2005, and $322 million in 2004 which are included in Capital Expenditures for Residential Real Estate within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows. |
| (c) | As a result of the deconsolidation of Crescent, effective September 7, 2006, Crescent amounts for 2006 only include Crescent capital and investment expenditures for periods prior to September 7, 2006. |
Financing Cash Flows and Liquidity
Spectra Energy Capital’s consolidated capital structure as of December 31, 2006, including short-term debt, was 58% debt, 38% member’s equity and 4% minority interests. The fixed charges coverage ratio, calculated using SEC guidelines, was 3.1 times for 2006, which includes a pre-tax gain of approximately $250 million on the sale of an effective 50% interest in Crescent, 4.3 times for 2005, which includes a pre-tax gain on the sale of TEPPCO GP and LP of approximately $0.9 billion, net of minority interest, and 1.7 times for 2004.
Net cash used in financing activities was $2,454 million in 2006 compared to $2,341 million in 2005, an increase of $113 million. The change was due primarily to the following:
| • | Approximately $1.0 billion increase in distributions to parent, net of capital contributions, in 2006, due primarily to the debt proceeds from the Crescent JV transaction and the transfer of cash held at Bison and Spectra Energy Capital businesses transferred to Duke Energy during 2006; partially offset by |
| • | Approximately $0.7 billion increase in proceeds from the issuance of long-term debt, commercial paper and notes payable in 2006, net of redemptions, due primarily to the debt proceeds from the Crescent JV transaction. |
Net cash used in financing activities was $2,341 million in 2005 compared to $2,902 million in 2004, a decrease of $561 million. The change was due primarily to the following:
| • | Approximately $2.5 billion of higher net paydowns of long-term debt, commercial paper, notes payable, and preferred stock of a subsidiary during 2004 in connection with an effort to reduce debt balances, |
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| • | Approximately $120 million of lower net distributions to minority interest in 2005, and |
| • | $110 million of proceeds in 2005 from the Income Fund’s issuance of Trust units. |
This decrease was partially offset by:
| • | An increase of approximately $1.8 billion of net distributions to Duke Energy and, |
| • | An increase of approximately $350 million of advances to Duke Energy in 2005 as compared to 2004. |
Significant Financing Activities—Year Ended 2006.
During the year ended December 31, 2006, Spectra Energy Capital terminated an $800 million syndicated credit facility and $710 million of other bi-lateral credit facilities, offset by the addition of a new $350 million syndicated credit facility. The terminations of these credit facilities primarily reflect Spectra Energy Capital’s reduced liquidity needs as a result of exiting the DENA business.
In November 2006, Union Gas issued 125 million Canadian dollars of 4.85% fixed-rate debentures (approximately $108 million U.S. dollar equivalents as of the closing date) due in 2022.
In September 2006, prior to the completion of the partial sale of Crescent to the MS Members as discussed in Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale,” Crescent issued approximately $1.23 billion principal amount of debt. The net proceeds from the debt issuance of approximately $1.21 billion were recorded as a Financing Activity on the Consolidated Statements of Cash Flows. As a result of Spectra Energy Capital’s deconsolidation of Crescent effective September 7, 2006, Crescent’s outstanding debt balance of $1,298 million was removed from Spectra Energy Capital’s Consolidated Balance Sheets.
In September 2006, Union Gas issued 165 million Canadian dollars of 5.46% fixed-rate debentures (approximately $148 million in U.S. dollar equivalents as of the issuance date) due in 2036.
In September 2006, the Income Fund sold approximately 9 million previously unissued Trust Units for proceeds of $94 million, net of commissions and other expenses of issuance. The sale of these Trust Units reduced Spectra Energy Capital’s ownership interest in the Income Fund to approximately 46% at December 31, 2006. As a result of the sale of additional Trust Units, Spectra Energy Capital recognized an approximate $15 million pre-tax SAB No. 51 gain on the sale of subsidiary stock. The proceeds from the offering plus the draw down of approximately 39 million Canadian dollars on an available credit facility were used by the Income Fund to acquire a 100% interest in Westcoast Gas Services, Inc. from Spectra Energy Capital.
During 2006, Spectra Energy Capital advanced approximately $89 million to its parent, Duke Energy, and forgave advances to Duke Energy of approximately $602 million. Additionally, during 2006, Spectra Energy Capital distributed approximately $2,361 million to Duke Energy to provide funding support for Duke Energy’s dividend payments and share repurchase plan. The distribution was principally obtained from the proceeds received on Spectra Energy Capital’s sale of 50% of Crescent to the MS Members.
Significant Financing Activities—Year Ended 2005.
In December 2005, the Income Fund, a Canadian income trust fund, was created which sold approximately 40% ownership in the Canadian Midstream operations for proceeds, net of underwriting discount, of approximately $110 million. In January 2006, a subsequent greenshoe sale of additional ownership interests, pursuant to an overallotment option, in the Income Fund were sold for approximately $10 million.
On September 21, 2005, Union Gas issued 200 million Canadian dollars of 4.64% fixed-rate debentures (approximately $171 million in U.S. dollar equivalents as of the issuance date) due in 2016.
In April 2005, Spectra Energy Capital received a $269 million capital contribution from Duke Energy, which Spectra Energy Capital classified as an addition to Member’s Equity.
During 2005, Spectra Energy Capital distributed $2.1 billion to its parent, Duke Energy, to principally provide for funding for the execution of Duke Energy’s accelerated share repurchase transaction and to provide
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funding support for Duke Energy’s dividend. The distribution was primarily obtained from Spectra Energy Capital’s portion of the cash proceeds realized from the sale by DCP Midstream of TEPPCO GP and Spectra Energy Capital’s sale of its limited partner interest in TEPPCO LP.
During 2004, $267 million of cash advances were received by Spectra Energy Capital from Duke Energy. During the first quarter of 2005, Duke Energy forgave these advances of $267 million and Spectra Energy Capital classified the $267 million as an addition to Member’s Equity. Additionally, during the third quarter of 2005, Duke Energy forgave additional advances of $494 million as an addition to Member’s Equity. These transactions are considered non-cash financing activity in the Consolidated Statements of Cash Flows for the year ended December 31, 2005.
Significant Financing Activities—Year Ended 2004.
In December 2004, Spectra Energy Capital reached an agreement to sell its partially completed Gray’s Harbor power generation facility (Grays Harbor) to an affiliate of Invenergy LLC. In 2004, Spectra Energy Capital terminated its capital lease with the dedicated pipeline which would have transported natural gas to Grays Harbor. As a result of this termination, approximately $94 million was paid by Spectra Energy Capital in January 2005.
Available Credit Facilities and Restrictive Debt Covenants. Spectra Energy 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, 2006, Spectra Energy 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 debt or credit agreements contain material adverse change clauses.
At December 31, 2006, Spectra Energy Capital and certain of its subsidiaries had approximately $695 million of credit facilities which expire in 2007. It is Spectra Energy Capital’s intent to replace the expiring credit facilities. (For information on Spectra Energy Capital’s credit facilities as of December 31, 2006, see Note 14 to the Consolidated Financial Statements, “Debt and Credit Facilities.”)
Credit Ratings. The short-term and long-term debt of Spectra Energy Capital and certain subsidiaries are rated by Standard & Poor’s (S&P), Moody’s Investors Service (Moody’s) and Dominion Bond Rating Service (DBRS).
Credit Ratings Summary as of March 23, 2007
Standard and | Moody’s Service | Dominion Bond Rating Service | ||||
Spectra Energy Capital (a) | BBB | Baa1 | Not applicable | |||
Texas Eastern Transmission, LP (a) | BBB+ | A3 | Not applicable | |||
Westcoast Energy Inc. (a) | BBB+ | Not applicable | A(low) | |||
Union Gas (a) | BBB+ | Not applicable | A | |||
Maritimes & Northeast Pipeline, LLC (b) | A | A2 | A | |||
Maritimes & Northeast Pipeline, LP (b) | A | A2 | A |
| (a) | Represents senior unsecured credit rating |
| (b) | Represents senior secured credit rating |
These entities credit ratings are dependent upon, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures, while maintaining the strength of their current balance sheets. These credit ratings could be negatively impacted if as a result of market conditions or other factors, they are unable to maintain their current balance sheet strength, or if earnings and cash flow outlook materially deteriorates.
Other Financing Matters. As of December 31, 2006, Spectra Energy Capital and its subsidiaries had effective SEC shelf registrations which allowed for the issuance of up to $592 million in gross proceeds from debt and other securities. Additionally, as of December 31, 2006, subsidiaries of Spectra Energy Capital had
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935 million Canadian dollars (approximately U.S. $807 million) available under Canadian shelf registrations for issuances in the Canadian market. Of the 935 million Canadian dollars available under Canadian shelf registrations, 500 million expires in May 2008 and 435 million expires in August 2008.
Spectra Energy currently anticipates a dividend payout ratio of approximately 60% of estimated annual net income per share of common stock. The declaration and payment of dividends will be subject to the sole discretion of Spectra Energy’s Board of Directors and will depend upon many factors, including the financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with certain of our debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by the Board of Directors. A first quarter dividend of $0.22 per share was declared on January 5, 2007 and paid on March 15, 2007.
On March 30, 2007, a subsidiary of Spectra Energy Capital filed a registration statement on Form S-1 with the SEC to register the initial public offering of limited partner units of a proposed MLP that would hold certain pipeline and storage assets of Spectra Energy Capital. The assets include a 100% interest in East Tennessee and a 50% interest in MHP, which are currently wholly-owned subsidiaries of Spectra Energy Capital, and a 24.5% interest in Gulfstream, representing approximately one-half of Spectra Energy Capital’s current 50% ownership interest in Gulfstream. Spectra Energy currently estimates that proceeds of approximately $300 million to $400 million would be received by Spectra Energy Capital upon closing of the transaction.
Off-Balance Sheet Arrangements
Spectra Energy 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 Spectra Energy 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 Spectra Energy 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 Spectra Energy Capital’s operations. Thus, if Spectra Energy Capital discontinued issuing these guarantee arrangements, there would not be a material impact to the consolidated results of operations, cash flows or financial position.
In contemplation of Duke Energy’s spin-off of the natural gas businesses on January 2, 2007, certain guarantees that were previously issued by Spectra Energy Capital were transferred to Duke Energy prior to the consummation of the spin-off. Duke Energy has indemnified Spectra Energy Capital against any losses incurred under the remaining guarantee obligations that relate to Duke Energy operations.
Spectra Energy Capital does not have any other material off-balance sheet financing entities or structures, except for normal operating lease arrangements, guarantee arrangements and financings entered into by equity investment pipeline and field services operations. (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
Spectra Energy 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 Spectra Energy 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, as well as future obligations of businesses included in discontinued operations for the year ended December 31, 2006 (see
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Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). It is expected that the majority of current liabilities on the Consolidated Balance Sheets will be paid in cash in 2007.
Contractual Obligations as of December 31, 2006
| Payments Due By Period | |||||||||||||||
| Total | Less than 1 year (2007) | 2-3 Years (2008 & 2009) | 4-5 Years (2010 & 2011) | More than 5 Years (Beyond 2012) | |||||||||||
| (in millions) | |||||||||||||||
Long-term debt (a) | $ | 13,954 | $ | 1,116 | $ | 2,335 | $ | 1,977 | $ | 8,526 | |||||
Capital leases (a) | 4 | 1 | 3 | — | — | ||||||||||
Operating leases (b) | 197 | 30 | 53 | 43 | 71 | ||||||||||
Purchase Obligations: (g) | |||||||||||||||
Firm capacity payments (c) | 1,541 | 395 | 306 | 236 | 604 | ||||||||||
Energy commodity contracts (d) | 1,080 | 891 | 189 | — | — | ||||||||||
Other purchase obligations (e) | 233 | 202 | 31 | — | — | ||||||||||
Other long-term liabilities on the Consolidated Balance Sheets (f) | — | — | — | — | — | ||||||||||
Total contractual cash obligations | $ | 17,009 | $ | 2,635 | $ | 2,917 | $ | 2,256 | $ | 9,201 | |||||
| (a) | See Note 14 to the Consolidated Financial Statements, “Debt and Credit Facilities.” Amount includes interest payments over life of debt or capital lease. |
| (b) | See Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies.” |
| (c) | Includes firm capacity payments that provide Spectra Energy Capital with uninterrupted firm access to natural gas transportation and storage. |
| (d) | Includes contractual obligations to purchase physical quantities of NGLs and natural gas, primarily for Union Gas’ distribution operations. Amount includes certain 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, 2006. |
| (e) | Includes contracts for software and consulting or advisory services. Amount also includes contractual obligations for engineering, procurement and construction costs for pipeline projects. Amount excludes certain open purchase orders for services that are provided on demand, and the timing of the purchase can not be determined. |
| (f) | Excludes cash obligations for asset retirement activities (see Note 6 to the Consolidated Financial Statements, “Asset Retirement Obligations”). The amount of cash flows to be paid to settle the asset retirement obligations is not known with certainty as Spectra Energy Capital may use internal resources or external resources to perform retirement activities. Asset retirement obligations recognized on the Consolidated Balance Sheets total $85 million at December 31, 2006. Amount excludes reserves for litigation, environmental remediation and self-insurance claims (see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies”) because Spectra Energy 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. |
| (g) | Purchase obligations reflected in the Consolidated Balance Sheets have been excluded from the above table. |
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Quantitative and Qualitative Disclosures About Market Risk
Risk and Accounting Policies
Spectra Energy 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. The Chief Financial Officer of Spectra Energy 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” for further discussion of the accounting for derivative contracts.
Disclosures about market risks related to businesses transferred to Duke Energy in December 2006 are not reflected herein since such exposures have no impact on the ongoing operations of Spectra Energy post spin-off.
Commodity Price Risk
Spectra Energy is exposed to the impact of market fluctuations in the prices of NGL’s and natural gas as a result of its investment in DCP Midstream, ownership of the Empress assets in Western Canada and processing plants associated with the U.S. pipeline assets. Price risk represents the potential risk of loss from adverse changes in the market price of these energy commodities. Spectra Energy’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.
Spectra Energy employs established policies and procedures to manage its risks associated with these market fluctuations, which may include the use of forward physical transactions as well as commodity derivatives, such as swaps and options. To the extent that instruments accounted for as hedges are 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 the use of contracts with different commodities or unmatched terms and counterparty credit risk. When hedge accounting is used, hedge effectiveness is monitored regularly and measured each month.
Spectra Energy is primarily exposed to market price fluctuations of NGL prices in the Field Services segment, which is involved in gathering and processing activities. NGL prices historically track crude oil prices, therefore, Spectra Energy is disclosing the NGL price sensitivities in terms of crude oil price changes. Based on a sensitivity analysis as of December 31, 2006 and 2005, at forecast NGL-to-oil price relationships, a $10 per barrel move in oil prices would affect Spectra Energy’s annual pre-tax earnings by approximately $170 million in 2007 and $95 million in 2006. In addition, with respect to the Empress processing and NGL marketing activities in Western Canada, as of December 31, 2006 and 2005, a $1 change in the difference between the Btu-equivalent price of propane (used as a proxy for Empress’ NGL production) and the price of natural gas in Alberta, Canada would affect Spectra Energy’s pre-tax earnings by approximately $25 million on an annual basis for both 2007 and 2006. The spread between NGL prices and the price of natural gas represents the theoretical gross margin for processing liquids from the gas and is commonly called the frac-spread. These hypothetical calculations consider prior hedge positions and estimated production levels, but do not consider other potential effects that might result from such changes in commodity prices.
See also 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.”
Credit Risk
Credit risk represents the loss that Spectra Energy would incur if a counterparty fails to perform under its contractual obligations. Spectra Energy’s principal customers for natural gas transportation, storage, and gathering and processing services are industrial end-users, marketers, local distribution companies and utilities
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located throughout the U.S. and Canada. Spectra Energy has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers and marketers. These concentrations of customers may affect Spectra Energy’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Credit risk associated with gas distribution services are primarily impacted by general economic conditions in the service territory. Where exposed to credit risk, Spectra Energy 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. Spectra Energy also obtains cash or letters of credit from customers to provide credit support, where appropriate, based on its financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction. Approximately 85% of Spectra Energy’s credit exposures for transportation, storage, and gathering and processing services are with customers who have an investment grade rating or equivalent based on an evaluation by Spectra Energy.
Spectra Energy had no net exposure to any one customer that represented greater than 10% of the gross fair value of trade accounts receivable at December 31, 2006. Based on Spectra Energy’s policies for managing credit risk, its exposures and its credit and other reserves, Spectra Energy does not anticipate a materially adverse effect on its consolidated financial position or results of operations as a result of non-performance by any counterparty.
In 1999, the Industrial Development Corp of the City of Edinburg, Texas (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo (Hidalgo), a subsidiary of Spectra Energy Capital. Spectra Energy Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Spectra Energy Capital remained obligated under the lease guaranty. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Gross, undiscounted exposure under the guarantee obligation as of December 31, 2006 is approximately $200 million, including principal and interest payments. Spectra Energy Capital does not believe a loss under the guarantee obligation is probable as of December 31, 2006, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of December 31, 2006. No demands for payment have been made under the guarantee. If losses are incurred under the guarantee, Spectra Energy Capital has certain rights which should allow it to mitigate such loss. Subsequent to Duke Energy’s January 2, 2007 spin-off of Spectra Energy Capital, this guarantee remained with Spectra Energy Capital. However, Duke Energy indemnified Spectra Energy Capital against any future losses that could arise from payments required under this guarantee.
Interest Rate Risk
Spectra Energy Capital is exposed to risk resulting from changes in interest rates as a result of its issuance of variable and fixed rate debt and commercial paper. Spectra Energy 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. Spectra Energy 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, 2006, it was estimated that if market interest rates average 1% higher (lower) in 2007 than in 2006, interest expense, net of offsetting impacts in interest income, would increase (decrease) by approximately $8 million. Comparatively, based on a sensitivity analysis as of December 31, 2005, had interest rates averaged 1% higher (lower) in 2006 than in 2005, it was estimated that interest expense, net of offsetting impacts in interest income, would have been immaterial. 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, 2006 and 2005. 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 Spectra Energy Capital’s financial structure.
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Equity Price Risk
Spectra Energy Capital’s wholly owned captive insurance subsidiary that began operations in January 2007, effective with the separation from Duke Energy, maintains investments to fund various business risks and losses, such as workers compensation, property, business interruption and general liability. The investments may be exposed to price fluctuations in equity markets and changes in interest rates in the future at the direction of an investment manager selected by Spectra Energy Capital management.
Spectra Energy’s costs of providing non-contributory defined benefit retirement and postretirement benefit 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.
Foreign Currency Risk
Spectra Energy is exposed to foreign currency risk from investments and operations in Canada. To mitigate risks associated with foreign currency fluctuations, investments are naturally hedged through debt denominated or issued in the foreign currency. Spectra Energy may also use foreign currency derivatives from time-to-time to manage its risk related to foreign currency fluctuations. To monitor its currency exchange rate risks, Spectra Energy uses sensitivity analysis, which measures the impact of devaluation of the Canadian dollar.
A 10% devaluation in the Canadian dollar exchange rate as of December 31, 2006 in Spectra Energy Capital’s currency exposure would result in an estimated net loss on the translation of local currency earnings of approximately $25 million to Spectra Energy Capital’s Consolidated Statements of Operations in 2007. The Consolidated Balance Sheet would be negatively impacted by approximately $460 million currency translation through the cumulative translation adjustment in AOCI as of December 31, 2006 as a result of a 10% devaluation in the currency exchange rate.
OTHER ISSUES
Global Climate Change. Spectra Energy’s assets and operations in the U.S. and Canada may become subject to direct and indirect effects of possible future global climate change regulatory actions. Canada is a party to the United Nations-sponsored Kyoto Protocol, which prescribes specific greenhouse gas emission-reduction targets for developed countries for the 2008-2012 period. The Canadian government is actively considering its approach to implementing its national obligation under the Kyoto Protocol, but that approach has not yet been determined.
The U.S. is not a party to the Kyoto Protocol, and the federal government has not adopted a mandatory greenhouse gas reduction requirement. While several bills have been introduced in the U.S. Congress that would impose greenhouse gas emission constraints, final legislation has yet to advance.
A number of states, primarily in the Northeast and Western U.S. are either in the process of establishing or considering state or regional programs that would mandate future reductions in greenhouse gas emissions. The final details and implementation schedules of such future state or regional programs, and whether they might directly affect the natural gas sector, are uncertain.
The likelihood of greenhouse gas regulation and the key details of future restrictions are highly uncertain, and thus the likely future affects on Spectra Energy are highly uncertain. Due to the speculative outlook regarding any U.S. federal and state policies and the uncertainty of the Canadian policy, Spectra Energy cannot estimate the potential effect of either nation’s greenhouse gas policy on its future combined results of operations, cash flows or financial position. Spectra Energy will monitor the development of greenhouse gas regulatory policies in both countries, and will assess the potential implications of greenhouse gas policies for its business operations in the U.S. and Canada if policies become sufficiently certain to support a meaningful assessment.
(For additional information on other issues related to Spectra Energy Capital, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies.”)
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New Accounting Standards
The following new accounting standards have been issued, but have not yet been adopted by Spectra Energy Capital as of December 31, 2006:
SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (SFAS No. 155).In February 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 155, which amendsSFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities”andSFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” (SFAS No. 140). SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for at fair value at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement (new basis) event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. SFAS No. 155 is effective for Spectra Energy Capital for all financial instruments acquired, issued, or subject to remeasurement after January 1, 2007, and for certain hybrid financial instruments that have been bifurcated prior to the effective date, for which the effect is to be reported as a cumulative-effect adjustment to beginning retained earnings. Spectra Energy Capital does not anticipate the adoption of SFAS No. 155 will have any material impact on its consolidated results of operations, cash flows or financial position.
SFAS No. 157, “Fair Value Measurements” (SFAS No. 157).In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements. However, in some cases, the application of SFAS No. 157 may change Spectra Energy Capital’s current practice for measuring and disclosing fair values under other accounting pronouncements that require or permit fair value measurements. For Spectra Energy Capital, SFAS No. 157 is effective as of January 1, 2008 and must be applied prospectively except in certain cases. Spectra Energy Capital is currently evaluating the impact of adopting SFAS No. 157, and cannot currently estimate the impact of SFAS No. 157 on its consolidated results of operations, cash flows or financial position.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS No. 159).In February 2007, the FASB issued SFAS No. 159, which permits entities to choose to measure many financial instruments and certain other items at fair value. For Spectra Energy Capital, SFAS No. 159 is effective as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. Spectra Energy Capital cannot currently estimate the impact of SFAS No. 159 on its consolidated results of operations, cash flows or financial position and has not yet determined whether or not it will choose to measure items subject to SFAS No. 159 at fair value.
FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48). In July 2006, the FASB issued FIN 48, which provides guidance on accounting for income tax positions about which Spectra Energy Capital has concluded there is a level of uncertainty with respect to the recognition in its financial statements. FIN 48 prescribes a minimum recognition threshold a tax position is required to meet. Tax positions are defined very broadly and include not only tax deductions and credits but also decisions not to file in a particular jurisdiction, as well as the taxability of transactions. Spectra Energy Capital will implement FIN 48 effective January 1, 2007. The implementation is expected to result in a cumulative effect adjustment to beginning Member’s Equity on the Consolidated Statement of Member’s Equity and Comprehensive Income (Loss) in the first quarter 2007 in the range of $15 million to $30 million. Corresponding entries will impact a variety of balance sheet line items, including Deferred Income Taxes, Taxes Accrued, Other Liabilities, and Goodwill. Upon implementation of FIN 48, Spectra Energy Capital will reflect interest expense related to taxes as Interest Expense, in the Consolidated Statement of Operations. In addition, subsequent accounting for FIN 48 (after January 1, 2007) will involve an evaluation to determine if any changes have occurred that would impact the existing uncertain tax positions as well as determining whether any new tax positions are uncertain. Any impacts resulting from the evaluation of existing uncertain tax positions or from the recognition of new uncertain tax positions would impact income tax expense and interest expense in the Consolidated Statement of Operations, with offsetting impacts to the balance sheet line items described above. Uncertain tax positions on consolidated or combined tax returns filed by Duke Energy which are indemnified by Spectra Energy will be recorded as payables to Duke Energy.
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FASB Staff Position (FSP) No. FAS 123(R)-5, “Amendment of FASB Staff Position FAS 123(R)-1” (FSP No. FAS 123(R)-5). In October 2006, the FASB staff issued FSP No. FAS 123(R)-5 to address whether a modification of an instrument in connection with an equity restructuring should be considered a modification for purposes of applyingFSP No. FAS 123(R)-1, “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R) (FSP No. FAS 123(R)-1).” In August 2005, the FASB staff issued FSP FAS 123(R)-1 to defer indefinitely the effective date of paragraphs A230—A232 of SFAS No. 123(R), and thereby require entities to apply the recognition and measurement provisions of SFAS No. 123(R) throughout the life of an instrument, unless the instrument is modified when the holder is no longer an employee. The recognition and measurement of an instrument that is modified when the holder is no longer an employee should be determined by other applicable generally accepted accounting principles. FSP No. FAS 123(R)-5 addresses modifications of stock-based awards made in connection with an equity restructuring and clarifies that for instruments that were originally issued as employee compensation and then modified, and that modification is made to the terms of the instrument solely to reflect an equity restructuring that occurs when the holders are no longer employees, no change in the recognition or the measurement (due to a change in classification) of those instruments will result if certain conditions are met. This FSP is effective for Spectra Energy Capital as of January 1, 2007. The impact to Spectra Energy Capital of applying FSP No. FAS 123(R)-5 in subsequent periods will be dependent upon the nature of any modifications to Spectra Energy Capital’s share-based compensation awards.
FSP No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” (FSP AUG AIR-1).In September 2006, the FASB Staff issued FSP No. AUG AIR-1. This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods, if no liability is required to be recorded for an asset retirement obligation based on a legal obligation for which the event obligating the entity has occurred. The FSP also requires disclosures regarding the method of accounting for planned major maintenance activities and the effects of implementing the FSP. The guidance in this FSP is effective for Spectra Energy Capital as of January 1, 2007 and will be applied and retrospectively for all financial statements presented. Spectra Energy Capital does not anticipate the adoption of FSP No. AUG AIR-1 will have any material impact on its consolidated results of operations, cash flows or financial position.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk.”
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Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Spectra Energy Corp:
We have audited the accompanying balance sheet of Spectra Energy Corp (the “Company”), as of December 31, 2006. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such balance sheet presents fairly, in all material respects, the financial position of Spectra Energy Corp at December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the balance sheet, the spin-off of the Company from Duke Energy Corporation was completed on January 2, 2007.
/s/ Deloitte & Touche LLP
Houston, Texas
April 2, 2007
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Spectra Energy Corp
Balance Sheet
| December 31, 2006 | ||||
ASSETS | ||||
Total Assets | $ | – | ||
LIABILITIES AND STOCKHOLDER’S EQUITY | ||||
Preferred Stock, $0.001 par, 22 million shares authorized, no shares outstanding at December 31, 2006 | $ | – | ||
Common stock, $0.001 par, one billion shares authorized, one thousand shares outstanding at December 31, 2006 | 1 | |||
Less receivable from Duke Energy Corporation | (1 | ) | ||
Total Liabilities and Stockholder’s Equity | $ | – | ||
See Notes to Financial Statements
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Spectra Energy Corp
Notes to Financial Statements
(1) General
Gas SpinCo, Inc. was incorporated in the state of Delaware on July 28, 2006. Effective November 8, 2006, Gas SpinCo. Inc., changed its name to Spectra Energy Corp (the Company). On July 28, 2006, Duke Energy Corporation (Duke Energy), the sole shareholder of the Company, subscribed for 1,000 shares of the Company’s common stock at par. The receivable from Duke Energy relates to the subscription for 1,000 shares of the Company and has been reflected as a deduction from stockholder’s equity on the accompanying balance sheet.
The Company was formed to hold the assets and liabilities associated with Duke Energy’s natural gas business, including the transmission and storage, distribution and gathering and processing businesses. See Note 2 for further discussion.
During the period from incorporation to the date of these financial statements, December 31, 2006, the Company had no operations and no cash flows.
(2) Subsequent Event
On December 8, 2006, Duke Energy announced that its Board of Directors formally approved the distribution (the Distribution) of all the shares of common stock of the Company to Duke Energy’s shareholders (on an as converted basis). On January 2, 2007, Duke Energy completed the Distribution. Duke Energy distributed to the Company all of the ownership interests in Spectra Energy Capital, LLC (formerly Duke Capital LLC), which owned the assets and operations of Duke Energy’s natural gas businesses, and distributed one-half share of common stock of the Company for each share of Duke Energy common stock held by Duke Energy shareholders of record as of the close of business on December 18, 2006.
As a result of the separation transactions, Spectra Energy Capital represents the predecessor of the Company for financial statement purposes. Future financial statements of the Company will reflect the financial statements of Spectra Energy Capital for all prior periods reported.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Member of Spectra Energy Capital, LLC:
We have audited the accompanying consolidated balance sheets of Spectra Energy Capital, LLC (formerly Duke Capital LLC) and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, member’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2006. 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 the Company’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. The Company 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 the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, 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 Spectra Energy Capital, LLC and subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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 to the consolidated financial statements, in 2006 the Company changed its method of accounting for defined benefit pension and other postretirement plans as a result of adopting Statement of Financial Accounting Standard No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.
As discussed in Notes 1 and 21 to the consolidated financial statements, all of the member’s equity of the Company was contributed by its parent, Duke Energy Corporation, to Spectra Energy Corp as a result of Duke Energy Corporation’s spin-off of the natural gas businesses effective January 2, 2007.
/s/ DELOITTE & TOUCHE LLP |
Charlotte, North Carolina |
April 2, 2007 |
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SPECTRA ENERGY CAPITAL, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions)
| Years Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
Operating Revenues | ||||||||||||
Regulated natural gas and natural gas liquids | $ | 3,987 | $ | 3,714 | $ | 3,272 | ||||||
Non-regulated electric, natural gas, natural gas liquids, and other | 545 | 5,740 | 10,161 | |||||||||
Total operating revenues | 4,532 | 9,454 | 13,433 | |||||||||
Operating Expenses | ||||||||||||
Natural gas and petroleum products purchased | 1,435 | 5,821 | 9,273 | |||||||||
Operation, maintenance and other | 1,202 | 1,338 | 1,425 | |||||||||
Fuel used in electric generation and purchased power | — | — | 92 | |||||||||
Depreciation and amortization | 489 | 611 | 733 | |||||||||
Property and other taxes | 208 | 228 | 212 | |||||||||
Impairments and other charges | — | 125 | 22 | |||||||||
Total operating expenses | 3,334 | 8,123 | 11,757 | |||||||||
Gains (Losses) on Sales of Other Assets and Other, net | 47 | 522 | (349 | ) | ||||||||
Operating Income | 1,245 | 1,853 | 1,327 | |||||||||
Other Income and Expenses | ||||||||||||
Equity in earnings of unconsolidated affiliates | 609 | 355 | 90 | |||||||||
(Losses) gains on sales and impairments of equity method investments | (3 | ) | 1,245 | (5 | ) | |||||||
Gain on sale of subsidiary stock | 15 | — | — | |||||||||
Other income and expenses, net | 115 | 68 | 221 | |||||||||
Total other income and expenses | 736 | 1,668 | 306 | |||||||||
Interest Expense | 605 | 675 | 858 | |||||||||
Minority Interest Expense | 45 | 511 | 214 | |||||||||
Earnings From Continuing Operations Before Income Taxes | 1,331 | 2,335 | 561 | |||||||||
Income Tax Expense from Continuing Operations | 395 | 926 | 1,268 | |||||||||
Income (Loss) From Continuing Operations | 936 | 1,409 | (707 | ) | ||||||||
Income (Loss) From Discontinued Operations, net of tax | 308 | (731 | ) | 593 | ||||||||
Income (Loss) Before Cumulative Effect of Change in Accounting Principle | 1,244 | 678 | (114 | ) | ||||||||
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest | — | (4 | ) | — | ||||||||
Net Income (Loss) | $ | 1,244 | $ | 674 | $ | (114 | ) | |||||
See Notes to Consolidated Financial Statements
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SPECTRA ENERGY CAPITAL, LLC
CONSOLIDATED BALANCE SHEETS
(In millions)
| December 31, | December 31, | |||||
| 2006 | 2005 | |||||
ASSETS | ||||||
Current Assets | ||||||
Cash and cash equivalents | $ | 299 | $ | 491 | ||
Short-term investments | — | 521 | ||||
Receivables (net of allowance for doubtful accounts of $13 at December 31, 2006 and $121 at December 31, 2005) | 779 | 1,935 | ||||
Inventory | 397 | 444 | ||||
Assets held for sale | — | 1,528 | ||||
Unrealized gains on mark-to-market and hedging transactions | — | 90 | ||||
Other | 150 | 1,599 | ||||
Total current assets | 1,625 | 6,608 | ||||
Investments and Other Assets | ||||||
Investments in unconsolidated affiliates | 1,618 | 1,931 | ||||
Goodwill | 3,507 | 3,775 | ||||
Notes receivable | 36 | 138 | ||||
Unrealized gains on mark-to-market and hedging transactions | 17 | 87 | ||||
Assets held for sale | — | 3,597 | ||||
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $17 at December 31, 2005) | — | 1,281 | ||||
Other | 56 | 737 | ||||
Total investments and other assets | 5,234 | 11,546 | ||||
Property, Plant and Equipment | ||||||
Cost | 15,639 | 19,341 | ||||
Less accumulated depreciation and amortization | 3,245 | 3,655 | ||||
Net property, plant and equipment | 12,394 | 15,686 | ||||
Regulatory Assets and Deferred Debits | 1,092 | 1,216 | ||||
Total Assets | $ | 20,345 | $ | 35,056 | ||
See Notes to Consolidated Financial Statements
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SPECTRA ENERGY CAPITAL, LLC
CONSOLIDATED BALANCE SHEETS
(In millions)
| December 31, 2006 | December 31, 2005 | |||||
LIABILITIES AND MEMBER’S EQUITY | ||||||
Current Liabilities | ||||||
Accounts payable | $ | 246 | $ | 1,837 | ||
Notes payable and commercial paper | 349 | 83 | ||||
Taxes accrued | 214 | 258 | ||||
Interest accrued | 149 | 155 | ||||
Liabilities associated with assets held for sale | — | 1,488 | ||||
Current maturities of long-term debt | 550 | 1,394 | ||||
Unrealized losses on mark-to-market and hedging transactions | 7 | 207 | ||||
Other | 843 | 1,892 | ||||
Total current liabilities | 2,358 | 7,314 | ||||
Long-term Debt | 7,726 | 8,790 | ||||
Deferred Credits and Other Liabilities | ||||||
Deferred income taxes | 2,980 | 3,167 | ||||
Unrealized losses on mark-to-market and hedging transactions | 13 | 19 | ||||
Liabilities associated with assets held for sale | — | 2,085 | ||||
Other | 1,064 | 1,428 | ||||
Total deferred credits and other liabilities | 4,057 | 6,699 | ||||
Commitments and Contingencies | ||||||
Minority Interests | 565 | 749 | ||||
Member’s Equity | ||||||
Member’s Equity | 4,598 | 10,848 | ||||
Accumulated other comprehensive income | 1,041 | 656 | ||||
Total member’s equity | 5,639 | 11,504 | ||||
Total Liabilities and Member’s Equity | $ | 20,345 | $ | 35,056 | ||
See Notes to Consolidated Financial Statements
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SPECTRA ENERGY CAPITAL, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
Net income (loss) | $ | 1,244 | $ | 674 | $ | (114 | ) | |||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Depreciation and amortization | 606 | 774 | 1,014 | |||||||||
Cumulative effect of change in accounting principle | — | 4 | — | |||||||||
Gains on sales of investments in commercial and multi-family real estate | (201 | ) | (191 | ) | (201 | ) | ||||||
Gains on sales of equity investments and other assets | (308 | ) | (1,764 | ) | (192 | ) | ||||||
Impairment charges | 48 | 159 | 194 | |||||||||
Deferred income taxes | 104 | (240 | ) | 1,136 | ||||||||
Minority Interest | 60 | 538 | 195 | |||||||||
Equity in earnings of unconsolidated affiliates | (712 | ) | (479 | ) | (154 | ) | ||||||
Contribution to company-sponsored pension plans | (48 | ) | (45 | ) | (29 | ) | ||||||
Distributions from equity investments | 707 | 473 | 139 | |||||||||
(Increase) decrease in | ||||||||||||
Net realized and unrealized mark-to-market and hedging transactions | 16 | 534 | 208 | |||||||||
Receivables | 167 | (243 | ) | (251 | ) | |||||||
Inventory | 115 | (74 | ) | 17 | ||||||||
Other current assets | 1,272 | (969 | ) | 38 | ||||||||
Increase (decrease) in | ||||||||||||
Accounts payable | (690 | ) | 126 | 99 | ||||||||
Taxes accrued | 53 | 56 | 314 | |||||||||
Other current liabilities | (461 | ) | 558 | 86 | ||||||||
Capital expenditures for residential real estate | (322 | ) | (355 | ) | (322 | ) | ||||||
Cost of residential real estate sold | 143 | 294 | 268 | |||||||||
Other, assets | (749 | ) | 1,136 | (239 | ) | |||||||
Other, liabilities | (351 | ) | 106 | 31 | ||||||||
Net cash provided by operating activities | 693 | 1,072 | 2,237 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
Capital expenditures | (987 | ) | (997 | ) | (1,035 | ) | ||||||
Investment expenditures | (87 | ) | (23 | ) | (25 | ) | ||||||
Acquisitions, net of cash acquired | (89 | ) | (294 | ) | — | |||||||
Purchases of available-for-sale securities | (9,290 | ) | (30,918 | ) | (55,010 | ) | ||||||
Proceeds from sales and maturities of available-for-sale securities | 9,775 | 30,706 | 54,537 | |||||||||
Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable | 2,025 | 2,372 | 1,651 | |||||||||
Proceeds from the sales of commercial and multi-family real estate | 254 | 372 | 606 | |||||||||
Settlement of net investment hedges and other investing derivatives | (163 | ) | (296 | ) | — | |||||||
Distributions from equity investments | 152 | 383 | — | |||||||||
Other | (21 | ) | (64 | ) | 36 | |||||||
Net cash provided by investing activities | 1,569 | 1,241 | 760 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
Proceeds from the: | ||||||||||||
Issuance of long-term debt | 1,799 | 543 | 153 | |||||||||
Payments for the redemption of: | ||||||||||||
Long-term debt | (1,662 | ) | (840 | ) | (2,815 | ) | ||||||
Preferred stock of a subsidiary | (1 | ) | — | (176 | ) | |||||||
Decrease in cash overdrafts | ||||||||||||
Notes payable and commercial paper | 261 | 15 | 11 | |||||||||
Distributions to minority interests | (304 | ) | (861 | ) | (1,477 | ) | ||||||
Contributions from minority interests | 247 | 779 | 1,277 | |||||||||
Advances (to) from parent | (89 | ) | (242 | ) | 107 | |||||||
Capital contributions from parent | — | 269 | — | |||||||||
Distributions to parent | (2,361 | ) | (2,100 | ) | — | |||||||
Cash associated with operations transferred | (427 | ) | — | — | ||||||||
Proceeds from Spectra Energy Income Fund | 104 | 110 | — | |||||||||
Other | (21 | ) | (14 | ) | 18 | |||||||
Net cash used in financing activities | (2,454 | ) | (2,341 | ) | (2,902 | ) | ||||||
Changes in cash and cash equivalents included in assets held for sale | — | 3 | 39 | |||||||||
Net increase (decrease) in cash and cash equivalents | (192 | ) | (25 | ) | 134 | |||||||
Cash and cash equivalents at beginning of period | 491 | 516 | 382 | |||||||||
Cash and cash equivalents at end of period | $ | 299 | $ | 491 | $ | 516 | ||||||
Supplemental Disclosures | ||||||||||||
Cash paid for interest, net of amount capitalized | $ | 679 | $ | 833 | $ | 1,044 | ||||||
Cash paid (refunded) for income taxes | $ | 238 | $ | 486 | $ | (403 | ) | |||||
Significant non-cash transactions: | ||||||||||||
Transfer of legal entities to Duke Energy | $ | 2,952 | $ | — | $ | — | ||||||
Transfer of Midwestern assets to Duke Energy Ohio | $ | 1,462 | $ | — | $ | — | ||||||
Forgiveness of advances to Duke Energy | $ | 602 | $ | — | $ | — | ||||||
Transfer of Bison to Duke Energy | $ | 60 | $ | — | $ | — | ||||||
Distributions from parent | $ | — | $ | — | $ | — | ||||||
Advances from parent converted to equity | $ | — | $ | 761 | $ | — | ||||||
Debt retired in connection with disposition of businesses | $ | — | $ | — | $ | 840 | ||||||
Note receivable from sale of southeast plants | $ | — | $ | — | $ | 48 | ||||||
Remarketing of senior notes | $ | — | $ | — | $ | 1,625 | ||||||
Canadian midstream asset transfer | $ | — | $ | 97 | $ | — | ||||||
See Notes to Consolidated Financial Statements
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SPECTRA ENERGY CAPITAL, LLC
CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY AND COMPREHENSIVE INCOME
(In millions)
| Accumulated Other Comprehensive Income | ||||||||||||||||||||||||||||||||||||
| Paid-in Capital | Retained Earnings | Member’s Equity | Foreign Currency Adjustments | Net Gains (Losses) on Cash Flow Hedges | Minimum Pension Liability Adjustment | Other | FAS 158 Pension Adjustment | Total | ||||||||||||||||||||||||||||
Balance December 31, 2003 | $ | 8,563 | $ | 2,790 | $ | — | $ | 314 | $ | 310 | $ | (24 | ) | $ | — | $ | — | $ | 11,953 | |||||||||||||||||
Net loss | — | — | (114 | ) | — | — | — | — | — | (114 | ) | |||||||||||||||||||||||||
Conversion to Duke Capital LLC | (8,563 | ) | (2,790 | ) | 11,353 | — | — | — | — | — | — | |||||||||||||||||||||||||
Other Comprehensive Income | ||||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments | — | — | — | 279 | — | — | — | — | 279 | |||||||||||||||||||||||||||
Foreign currency translation adjustments reclassified into earnings as a result of the sale of Asia-Pacific Business | — | — | — | (54 | ) | — | — | — | — | (54 | ) | |||||||||||||||||||||||||
Net unrealized gains on cash flow hedges(a) | — | — | — | — | 300 | — | — | — | 300 | |||||||||||||||||||||||||||
Reclassification into earnings from cash flow hedges(b) | — | — | — | — | (80 | ) | — | — | — | (80 | ) | |||||||||||||||||||||||||
Minimum pension liability adjustment | — | — | — | — | — | 4 | — | — | 4 | |||||||||||||||||||||||||||
Total comprehensive income | 335 | |||||||||||||||||||||||||||||||||||
Other, net | — | — | (15 | ) | — | — | — | — | — | (15 | ) | |||||||||||||||||||||||||
Balance December 31, 2004 | $ | — | $ | — | $ | 11,224 | $ | 539 | $ | 530 | $ | (20 | ) | $ | — | $ | — | $ | 12,273 | |||||||||||||||||
Net income | — | — | 674 | — | — | — | — | — | 674 | |||||||||||||||||||||||||||
Other Comprehensive Income | ||||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments | — | — | — | 244 | — | — | — | — | 244 | |||||||||||||||||||||||||||
Net unrealized gains on cash flow hedges (a) | — | — | — | — | 409 | — | — | — | 409 | |||||||||||||||||||||||||||
Reclassification into earnings from cash flow hedges(b) | — | — | — | — | (1,025 | ) | — | — | — | (1,025 | ) | |||||||||||||||||||||||||
Minimum pension liability adjustment | — | — | — | — | — | (40 | ) | — | (40 | ) | ||||||||||||||||||||||||||
Net unrealized gains on FAS 115 securities | — | — | — | — | — | — | 19 | — | 19 | |||||||||||||||||||||||||||
Total comprehensive income | 281 | |||||||||||||||||||||||||||||||||||
Advances from parent converted to equity | — | — | 761 | — | — | — | — | — | 761 | |||||||||||||||||||||||||||
Capital contributions from parent | — | — | 269 | — | — | — | — | — | 269 | |||||||||||||||||||||||||||
Distribution to parent | — | — | (2,100 | ) | — | — | — | — | — | (2,100 | ) | |||||||||||||||||||||||||
Other, net | — | — | 20 | — | — | — | — | — | 20 | |||||||||||||||||||||||||||
Balance December 31, 2005 | $ | — | $ | — | $ | 10,848 | $ | 783 | $ | (86 | ) | $ | (60 | ) | $ | 19 | $ | — | $ | 11,504 | ||||||||||||||||
Net income | — | — | 1,244 | — | — | — | — | — | 1,244 | |||||||||||||||||||||||||||
Other Comprehensive Income | ||||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments | — | — | — | 106 | — | — | — | — | 106 | |||||||||||||||||||||||||||
Net unrealized gains (losses) on cash flow hedges(a) | — | — | — | — | (6 | ) | — | — | — | (6 | ) | |||||||||||||||||||||||||
Net unrealized gains on FAS 115 securities (e) | — | — | — | — | — | — | 14 | — | 14 | |||||||||||||||||||||||||||
Reclassification into earnings from cash flow hedges(b) | — | — | — | — | 39 | — | — | — | 39 | |||||||||||||||||||||||||||
Reclassification into earnings of FAS 115 investments(g) | — | — | — | — | — | — | (33 | ) | — | (33 | ) | |||||||||||||||||||||||||
Transfer of taxes on net investment hedge and other hedges to Duke Capital | — | — | — | 62 | 7 | — | — | — | 69 | |||||||||||||||||||||||||||
Transfer of legal entities to Duke Energy | — | — | — | 205 | — | — | — | — | 205 | |||||||||||||||||||||||||||
Transfer of Midwestern assets to Duke energy Ohio(c) | — | — | — | — | 40 | — | — | — | 40 | |||||||||||||||||||||||||||
Minimum pension liability adjustment (d) | — | — | — | — | — | (1 | ) | — | — | (1 | ) | |||||||||||||||||||||||||
Total comprehensive income | 1,677 | |||||||||||||||||||||||||||||||||||
Transfer of Midwestern assets to Duke Energy Ohio | — | — | (1,462 | ) | — | — | — | — | — | (1,462 | ) | |||||||||||||||||||||||||
Transfer of Bison to Duke Energy | — | — | (60 | ) | — | — | — | — | — | (60 | ) | |||||||||||||||||||||||||
Forgiveness of advances to Duke Energy | — | — | (602 | ) | — | — | — | — | — | (602 | ) | |||||||||||||||||||||||||
Distribution to parent | — | — | (796 | ) | — | — | — | — | — | (796 | ) | |||||||||||||||||||||||||
Distribution to parent associated with sale of Crescent | — | — | (1,602 | ) | — | — | — | — | — | (1,602 | ) | |||||||||||||||||||||||||
Transfer of legal entities to Duke Energy | — | — | (2,952 | ) | — | — | — | — | — | (2,952 | ) | |||||||||||||||||||||||||
Pension Adjustment—FAS 158 transition(f) | — | — | — | — | — | 61 | — | (109 | ) | (48 | ) | |||||||||||||||||||||||||
Other, net | — | — | (20 | ) | — | — | — | — | — | (20 | ) | |||||||||||||||||||||||||
Balance December 31, 2006 | $ | — | $ | — | $ | 4,598 | $ | 1,156 | $ | (6 | ) | $ | — | $ | — | $ | (109 | ) | $ | 5,639 | ||||||||||||||||
| (a) | Net unrealized gains on cash flow hedges, net of $3 tax benefit in 2006, $234 tax expense in 2005, and $180 tax expense in 2004. |
| (b) | Reclassification into earnings from cash flow hedges, net of $20 tax expense in 2006, $584 tax benefit in 2005, and $48 tax benefit in 2004. |
| (c) | Net of $24 tax expense in 2006. |
| (d) | Minimum pension liability adjustment, net of $27 tax benefit in 2005, and $2 tax expense in 2004. |
| (e) | Net of $8 tax expense in 2006, and $10 tax expense in 2005. |
| (f) | FAS 158 pension adjustment, net of $27 tax benefit in 2006 (see note 19). |
| (g) | Net of $18 tax benefit in 2006. |
See Notes to Consolidated Financial Statements
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements
For the Years Ended December 31, 2006, 2005 and 2004
1. Summary of Significant Accounting Policies
Nature of Operations and Basis of Consolidation. Spectra Energy Capital, LLC (collectively with its subsidiaries, Spectra Energy Capital, formerly Duke Capital LLC), a wholly owned subsidiary of Duke Energy Corporation (Duke Energy) until January 2, 2007, at which time Spectra Energy Capital became a wholly owned subsidiary of Spectra Energy Corp (Spectra Energy) as discussed below, is an energy company located in the Americas. These Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of Spectra Energy Capital and all majority-owned subsidiaries where Spectra Energy Capital has control, and those variable interest entities where Spectra Energy Capital is the primary beneficiary.
On April 1, 2006, Spectra Energy Capital transferred the operations of its wholly-owned captive insurance subsidiary, Bison Insurance Company Limited (Bison), to Duke Energy. Accordingly, Bison’s operations are not included in Spectra Energy Capital’s results of operations, financial position or cash flows subsequent to its transfer to Duke Energy. Due to continuing involvement between Bison and Spectra Energy Capital entities, the results of operations of Bison do not qualify for discontinued operations treatment.
Additionally, in April 2006, Spectra Energy Capital indirectly transferred to Duke Energy Ohio, Inc. (Duke Energy Ohio, formerly The Cincinnati Gas & Electric Company (CG&E)), a subsidiary of Cinergy, its ownership interest in former Duke Energy North America’s (DENA’s) Midwestern assets, representing a mix of combined cycle and peaking plants. In connection with this transfer, Spectra Energy Capital transferred to Duke Energy Ohio approximately $1.6 billion of assets at their carrying value and approximately $0.1 billion of liabilities at their carrying value, for a net transfer of approximately $1.5 billion. This transfer has been accounted for as a capital distribution at historical cost. In connection with the transfer, Spectra Energy Capital and Duke Energy Ohio entered into an arrangement through April 2016, unless otherwise extended by the parties, whereby Spectra Energy Capital will reimburse Duke Energy Ohio in the event of certain cash shortfalls that may result from Duke Energy Ohio’s ownership of the Midwestern assets. Payments made between Spectra Energy Capital and Duke Energy Ohio were immaterial during 2006. This agreement was assigned by Spectra Energy Capital to Duke Energy in the fourth quarter of 2006. The results of operations for former DENA’s Midwestern assets have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations up through the date of transfer.
On September 7, 2006, Spectra Energy Capital deconsolidated Crescent Resources, LLC (Crescent) due to a reduction in ownership and its inability to exercise control over Crescent (see Note 12). Crescent has been accounted for as an equity method investment since the date of deconsolidation.
Effective July 1, 2005, Spectra Energy Capital has deconsolidated DCP Midstream, LLC (formerly Duke Energy Field Services, LLC) (DCP Midstream) due to a reduction in ownership and its inability to exercise control over DCP Midstream (see Note 2). DCP Midstream has been subsequently accounted for as an equity method investment.
On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses to shareholders. The new natural gas business, which is named Spectra Energy, consists principally of the Natural Gas Transmission and Field Services business segments of Spectra Energy Capital, and excludes certain operations which were transferred from Spectra Energy Capital to Duke Energy in December 2006, primarily International Energy, Spectra Energy Capital’s effective 50% interest in Crescent and certain operations within Other, primarily Duke Energy Trading and Marketing, LLC (DETM), Duke Energy Merchants, LLC (DEM), DukeNet Communications, LLC (DukeNet), and Spectra Energy Capital’s 50% interest in Duke/Fluor Daniel (D/FD). The results of operations of most of these transferred businesses are included in discontinued operations in the accompanying Consolidated Statements of Operations for all periods presented. Corporate service companies that were transferred to Duke Energy in December 2006 are reported within continuing operations of Spectra Energy Capital since corporate services are expected to be provided to support the operations of Spectra Energy. In addition, although there are no assets or operations of the Commercial Power segment of Spectra
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Energy Capital, certain power plant operations within the previous Commercial Power segment of Spectra Energy Capital are reported in continuing operations as a result of continuing involvement by Spectra Energy Capital in 2005 subsequent to the sale of such operations in 2004. See further discussion in Notes 2 and 12.
Use of Estimates. To conform to generally accepted accounting principles (GAAP) in the United States, management makes estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and Notes. Although these estimates are based on management’s best available knowledge at the time, actual results could differ.
Reclassifications and Revisions. Certain prior period amounts have been reclassified within the Consolidated Statements of Cash Flows to conform to current year presentation.
Cash and Cash Equivalents. All highly liquid investments with original maturities of three months or less at the date of acquisition are considered cash equivalents.
Short-term Investments. Spectra Energy Capital may actively invest 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 7 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 Spectra Energy 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. Spectra Energy 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,” (SFAS No. 115), 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 the carrying values approximate market values due to their short-term maturities and no credit risk. 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 as incurred. Purchases and sales of available-for-sale securities are presented on a gross basis within Investing Cash Flows in the accompanying Consolidated Statements of Cash Flows.
Inventory. Inventory consists primarily of natural gas and natural gas liquids (NGLs) held in storage for transmission and processing, and also includes materials and supplies. Natural gas inventories primarily relate to the distribution business in Canada and are valued at costs approved by the regulator. The difference between the approved price and the actual cost of gas purchased is recorded in either accounts receivable or other current liabilities for future disposition with customers, subject to approval by the regulator. The remaining inventory is recorded at the lower of cost or market value, primarily using the average cost method.
Components of Inventory
| December 31, | ||||||
| 2006 | 2005 | |||||
| (in millions) | ||||||
Natural gas | $ | 290 | $ | 269 | ||
Materials and supplies | 90 | 130 | ||||
Petroleum products | 17 | 45 | ||||
Total inventory | $ | 397 | $ | 444 | ||
Accounting for Risk Management and Hedging Activities and Financial Instruments. Spectra Energy 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, such as swaps, futures, forwards and options.
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SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
All derivative instruments not designated as hedges or qualifying for the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), 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. Cash inflows and outflows related to derivative instruments, except those that contain financing elements and those related to net investment hedges and other investing activities, are a component of operating cash flows in the accompanying Consolidated Statements of Cash Flows. Cash inflows and outflows related to derivative instruments containing financing elements are a component of financing cash flows in the accompanying Consolidated Statements of Cash Flows while cash inflows and outflows related to net investment hedges and derivatives related to other investing activities are a component of investing cash flows in the accompanying Consolidated Statements of Cash Flows.
Spectra Energy Capital designates 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 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.
Classification of Contract | Spectra Energy Capital Accounting Model | Presentation of Gains & Losses or Revenue & Expense | ||
Non-trading derivatives: | ||||
Cash flow hedge | Accrual(b) | Gross basis in the same statement of operations category as the related hedged item | ||
Fair value hedge | Accrual(b) | Gross basis in the same statement of operations category as the related hedged item | ||
Undesignated | Mark-to-market(a) | Net basis in the related statement of operations category for interest rate, currency and commodity derivatives |
| (a) | An accounting term used by Spectra Energy 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, with the exception of Union Gas Limited’s (Union Gas) regulated business, which is recognized as a regulatory asset or liability. This term is applied to undesignated non-trading derivative contracts. As this term is not explicitly defined within GAAP, Spectra Energy Capital’s application of this term could differ from that of other companies. |
| (b) | An accounting term used by Spectra Energy 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 and fair value hedges, as well as to non-derivative contracts used for commodity risk management purposes. As this term is not explicitly defined within GAAP, Spectra Energy Capital’s application of this term could differ from that of other companies. |
Where Spectra Energy Capital’s derivative instruments are subject to a master netting agreement and the criteria of the Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 39, “Offsetting of Amounts Related to Certain Contracts—An Interpretation of Accounting Principles Board (APB) Opinion No. 10 and FASB Statement No. 105” (FIN 39), are met, Spectra Energy Capital presents its derivative assets and liabilities, and accompanying receivables and payables, on a net basis in the accompanying Consolidated Balance Sheets. As of December 31, 2006, subsequent to the transfer of businesses to Duke Energy, Spectra Energy Capital does not have any significant outstanding derivative instruments and does not participate in master netting arrangements in the normal course of its business.
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
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
recognized asset, liability or firm commitment (fair value hedge). For all hedge contracts, Spectra Energy Capital prepares formal documentation of the hedge in accordance with SFAS No. 133. In addition, at inception and every three months, Spectra Energy Capital formally assesses whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. Spectra Energy 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 Equity and Comprehensive Income as Accumulated Other Comprehensive Income (AOCI) until earnings are affected by the hedged transaction. Spectra Energy 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 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 probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in current earnings.
For derivatives designated as fair value hedges, Spectra Energy 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.
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. Spectra Energy Capital evaluates goodwill for potential impairment under the guidance of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). Under this standard, goodwill is subject to an annual test for impairment. Spectra Energy 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, Spectra Energy Capital performs the annual review for goodwill impairment at the reporting unit level, which Spectra Energy 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 implied 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 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.
Spectra Energy Capital primarily 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 and estimated future cash flows. In estimating cash flows, Spectra Energy Capital incorporates expected growth rates, regulatory stability, the ability to renew contracts, and foreign currency exchange rates, as well as other factors that affect its revenue and expense forecasts.
Property, Plant and Equipment. Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation. Spectra Energy Capital capitalizes all construction-related direct labor and
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SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
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, including depreciation associated with businesses included in discontinued operations were 3.32% for 2006, 3.60% for 2005, and 3.84% for 2004. Also, see “Allowance for Funds Used During Construction (AFUDC),” discussed below.
When Spectra Energy 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 in earnings, unless otherwise required by the applicable regulatory body.
Spectra Energy Capital recognizes asset retirement obligations (ARO’s) in accordance with SFAS No. 143, “Accounting For Asset Retirement Obligations” (SFAS No. 143), 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 and FIN No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), for conditional ARO’s in which the timing or method of settlement are conditional on a future event that may or may not be within the control of Spectra Energy Capital. Both SFAS No. 143 and FIN 47 require that the fair value of a liability for an ARO 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.
Long-Lived Asset Impairments, Assets Held For Sale and Discontinued Operations. Spectra Energy 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 undiscounted 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.
Spectra Energy Capital uses the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (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. When an asset or asset group meets the SFAS No. 144 criteria for classification as held for sale within the Consolidated Balance Sheets, Spectra Energy Capital does not retrospectively adjust prior period balance sheets to conform to current year presentation.
Spectra Energy Capital uses the criteria in SFAS No. 144 and Emerging Issues Task Force (EITF)03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Discontinued Operations” (EITF 03-13), to determine whether components of Spectra Energy Capital that are being disposed of or are classified as held for sale are required to be reported as discontinued operations in the Consolidated Statements of Operations. To qualify as a discontinued operation under SFAS No. 144, the component being disposed of must have clearly distinguishable operations and cash flows. Additionally, pursuant to EITF 03-13, Spectra Energy Capital must not have significant continuing involvement in the operations after the disposal (i.e. Spectra Energy Capital must not have the ability to influence the operating or financial policies of the disposed component) and cash flows of the operations being disposed of must have been eliminated from Spectra Energy Capital’s ongoing operations (i.e. Spectra Energy Capital does not expect to generate significant direct cash flows from activities involving the disposed component after the disposal transaction is completed). Assuming both preceding conditions are met, the related results of operations for the current and prior periods, including any related impairments, are reflected as Income (Loss) From Discontinued Operations, net of tax, in the Consolidated Statements of Operations. If an asset held for sale does not meet the requirements for discontinued operations classification, any impairments and gains or losses on sales are recorded in continuing operations as Gains (Losses) on Sales of Other Assets and Other, net, in the Consolidated Statements of Operations. Impairments for all other long-lived assets, excluding goodwill, are recorded as Impairment and Other Charges in the Consolidated Statements of Operations.
Captive Insurance Reserves. Prior to April 1, 2006, Spectra Energy Capital had captive insurance subsidiaries which provided insurance coverage to Spectra Energy 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 included 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. Subsequent to April 1, 2006, Spectra Energy Capital was provided insurance coverage through a captive insurance company of its parent, Duke Energy, as well as certain third parties. Effective January 2, 2007, this coverage and the associated insurance assets and liabilities applicable to the ongoing operations of Spectra Energy Capital transferred to a new captive insurance subsidiary of Spectra Energy Capital.
Spectra Energy Capital’s captive insurance entities also had reinsurance coverage, which provided reimbursement to Spectra Energy Capital for certain losses above a per incident and/or aggregate retention. Spectra Energy Capital’s captive insurance entities also had an aggregate stop-loss insurance coverage, which provided reimbursement from third parties to Spectra Energy Capital for its paid losses above certain per line of coverage aggregate amounts during a policy year. Spectra Energy Capital recognized 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 by its captive insurance companies.
During 2004, Spectra Energy Capital eliminated intercompany reserves at its captive insurance subsidiaries of approximately $59 million which was a correction of an immaterial accounting error related to prior periods.
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. Spectra Energy 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 the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are reasonably estimable and probable.
Cost-Based Regulation. Spectra Energy Capital accounts for certain of its regulated operations under the provisions of SFAS No. 71, “Accounting for Certain Types of Regulation” (SFAS No. 71). The economic effects
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
of regulation can result in a regulated company recording assets for 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, Spectra Energy 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 and recent rate orders applicable to other regulated entities. 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. Spectra Energy 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, Spectra Energy Capital may have to reduce its 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. Spectra Energy Capital accounts for guarantees and related contracts, for which it is the guarantor, under FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). In accordance with FIN 45, upon issuance or modification of a guarantee on or after January 1, 2003, Spectra Energy 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, if any. Fair value is estimated using a probability-weighted approach. Spectra Energy 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 outside the scope of FIN 45 is accounted for and recognized in accordance with SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5).
Spectra Energy 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. Spectra Energy Capital’s 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 (see Note 17).
Stock-Based Compensation. Effective January 1, 2006, Spectra Energy Capital adopted the provisions of SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123(R)) (see Note 18). SFAS No. 123(R) establishes accounting for stock-based awards exchanged for employee and certain non-employee services. Accordingly, for employee awards, equity classified stock-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as expense over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Awards, including stock options, granted to employees that are already retirement eligible are deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards is recognized on the date such awards are granted.
Spectra Energy Capital elected to adopt the modified prospective application method as provided by SFAS No. 123(R), and accordingly, financial statement amounts for periods prior to January 1, 2006 in this Form 10-K have not been restated. There were no modifications to outstanding stock options prior to the adoption of SFAS 123(R). Spectra Energy Capital has historically been allocated its proportionate share of stock-based compensation expense from its parent, Duke Energy.
Spectra Energy Capital previously applied Accounting Principles Board (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 25” and provided the required pro forma disclosures of SFAS
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). Since the exercise price for all stock options granted under those plans was equal to the market value of the underlying common stock on the grant date, no compensation cost was recognized in the accompanying Consolidated Statements of Operations.
Revenue Recognition. Revenues on sales of natural gas, natural gas transportation, storage and distribution as well as sales of petroleum products 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, commodity prices and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actual and estimated unbilled revenues are immaterial.
Allowance for Funds Used During Construction (AFUDC). AFUDC, which represents 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, Spectra Energy 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 $21 million in 2006, which consisted of an equity component of $11 million and an interest expense component of $10 million. The total amount of AFUDC included in the Consolidated Statements of Operations was $17 million in 2005, which consisted of an equity component of $8 million and an interest expense component of $9 million. The total amount of AFUDC included in the Consolidated Statements of Operations was $17 million in 2004, which consisted of an equity component of $9 million and an interest expense component of $8 million.
Accounting For Sales of Stock by a Subsidiary. Spectra Energy Capital accounts for sales of stock by a subsidiary under Staff Accounting Bulletin (SAB) No. 51, “Accounting for Sales of Stock of a Subsidiary” (SAB 51). Under SAB 51, companies may elect, via an accounting policy decision, to record a gain on the sale of stock of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the shares. Spectra Energy Capital has elected to treat such excesses as gains in earnings, which are reflected in Gain on Sale of Subsidiary Stock in the Consolidated Statements of Operations. During the year ended December 31, 2006, Spectra Energy Capital recognized a gain of approximately $15 million related to the sale of securities of the Spectra Energy Income Fund (Income Fund), formerly the Duke Energy Income Fund (see Note 2).
Income Taxes. As a result of Duke Energy’s merger with Cinergy, Spectra Energy Capital and its subsidiaries entered into a tax sharing agreement with Duke Energy, effective April 1, 2006, where the separate return method is used to allocate income taxes to Duke Energy’s subsidiaries based on the results of their operations. The accounting for income taxes essentially represents the income taxes that Spectra Energy Capital would incur if Spectra Energy Capital were a separate company filing its own tax return as a C-Corporation. Prior to entering into this tax sharing agreement, Spectra Energy Capital and Duke Energy Americas (DEA) were pass-through entities for U.S. income tax purposes.
Management evaluates and records contingent tax liabilities and related interest based on the probability of ultimately sustaining the tax deductions or income positions. Management assesses the probabilities of successfully defending the tax deductions or income positions based upon statutory, judicial or administrative authority.
Segment Reporting. SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (SFAS No. 131), 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 reportable segment provided aggregation is consistent
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
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. There is no aggregation within Spectra Energy Capital’s defined business segments. 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 general-purpose financial statements, and changes in the measurement of segment amounts from period to period. The description of Spectra Energy 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 Spectra Energy 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 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. Gains and losses arising from transactions denominated in currencies other than the functional currency, 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 Spectra Energy 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.
Statements of Consolidated Cash Flows. Spectra Energy Capital has made certain classification elections within its Consolidated Statements of Cash Flows related to discontinued operations, cash received from insurance proceeds and cash overdrafts. Cash flows from discontinued operations are combined with cash flows from continuing operations within operating, investing and financing cash flows within the Consolidated Statements of Cash Flows. Cash received from insurance proceeds are classified depending on the activity that resulted in the insurance proceeds (for example, business interruption insurance proceeds are included as a component of operating activities while insurance proceeds from damaged property are included as a component of investing activities). With respect to cash overdrafts, book overdrafts are included within operating cash flows while bank overdrafts are included within financing cash flows.
Distributions from Equity Investees. Spectra Energy Capital considers dividends received from equity investees which do not exceed cumulative equity in earnings subsequent to the date of investment a return on investment and classifies these amounts as operating activities within the accompanying Consolidated Statements of Cash Flows. Cumulative dividends received in excess of cumulative equity in earnings subsequent to the date of investment are considered a return of investment and are classified as investing activities within the accompanying Consolidated Statements of Cash Flows.
Cumulative Effect of Changes in Accounting Principles. As of December 31, 2005, Spectra Energy Capital adopted the provisions of FIN 47. In accordance with the transition guidance of this standard, Spectra Energy Capital recorded a net-of-tax cumulative effect adjustment of approximately $4 million.
New Accounting Standards. The following new accounting standards were adopted by Spectra Energy Capital during the year ended December 31, 2006 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:
SFAS No. 123(R)“Share-Based Payment” (SFAS No. 123(R)). In December 2004, the FASB issued SFAS No. 123(R), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
based on their fair values. For Spectra Energy Capital, timing for implementation of SFAS No. 123(R) was January 1, 2006. The pro forma disclosures previously permitted under SFAS No. 123 are no longer an acceptable alternative. Instead, Spectra Energy Capital is required to determine an appropriate expense for stock options and record compensation expense in the Consolidated Statements of Operations for stock options. Spectra Energy Capital implemented SFAS No. 123(R) using the modified prospective transition method, which required Spectra Energy Capital to record compensation expense for all unvested awards beginning January 1, 2006.
Spectra Energy Capital currently also has retirement eligible employees with outstanding share-based payment awards (unvested stock awards, stock based performance awards and phantom stock awards). Compensation cost related to those awards was previously expensed over the stated vesting period or until actual retirement occurred. Effective January 1, 2006, Spectra Energy Capital is required to recognize compensation cost for new awards granted to employees over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Awards, including stock options, granted to employees that are already retirement eligible are deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards is recognized on the date such awards are granted.
The adoption of SFAS No. 123(R) did not have a material impact on Spectra Energy Capital’s consolidated results of operations, cash flows or financial position in 2006 based on awards outstanding as of the implementation date. However, the impact to Spectra Energy Capital in periods subsequent to adoption of SFAS No. 123(R) will be largely dependent upon the nature of any new share-based compensation awards issued to employees. (See Note 18.)
SAB No. 107, “Share-Based Payment” (SAB No. 107). On March 29, 2005, the Securities and Exchange Commission (SEC) staff issued SAB No. 107 to express the views of the staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. Spectra Energy Capital adopted SFAS No. 123(R) and SAB No. 107 effective January 1, 2006.
FASB Staff Position (FSP) No. FAS 123(R)-4, “Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event” (FSP No. FAS 123(R)-4). In February 2006, the FASB staff issued FSP FAS No. 123(R)-4 to address the classification of options and similar instruments issued as employee compensation that allow for cash settlement upon the occurrence of a contingent event. The guidance amends SFAS No. 123(R). FSP No. FAS 123(R)-4 provides that cash settlement features that can be exercised only upon the occurrence of a contingent event that is outside the employee’s control does not require classifying the option or similar instrument as a liability until it becomes probable that the event will occur. FSP No. FAS 123(R)-4 applies only to options or similar instruments issued as part of employee compensation arrangements. The guidance in FSP No. FAS 123(R)-4 was effective for Spectra Energy Capital as of April 1, 2006. Spectra Energy Capital adopted SFAS No. 123(R) as of January 1, 2006 (see Note 18). The adoption of FSP No. FAS 123(R)-4 did not have a material impact on Spectra Energy Capital’s consolidated statement of operations, cash flows or financial position.
FSP No. FAS 115-1 and 124-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments” (FSP No. FAS 115-1 and 124-1). The FASB issued FSP No. FAS 115-1 and 124-1 in November 2005, which was effective for Spectra Energy Capital beginning January 1, 2006. This FSP addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. This FSP also includes accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. The guidance in this FSP amends SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and SFAS No. 124, “Accounting for Certain Investments Held by Not-for-Profit Organizations,” and APB Opinion No. 18, “The
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Equity Method of Accounting for Investments in Common Stock” (APB 18). The adoption of FSP No. FAS 115-1 and 124-1 did not have a material impact on Spectra Energy Capital’s consolidated results of operations, cash flows or financial position.
FSP No. FIN 46(R)-6, “Determining the Variability to Be Considered In Applying FASB Interpretation No. 46(R) (FSP No. FIN 46(R)-6).” In April 2006, the FASB staff issued FSP No. FIN 46(R)-6 to address how to determine the variability to be considered in applying FIN 46(R), “Consolidation of Variable Interest Entities.” The variability that is considered in applying FIN 46(R) affects the determination of whether the entity is a variable interest entity (VIE), which interests are variable interests in the entity, and which party, if any, is the primary beneficiary of the VIE. The variability affects the calculation of expected losses and expected residual returns. This guidance is effective for all entities with which Spectra Energy Capital first becomes involved or existing entities for which a reconsideration event occurs after July 1, 2006. The adoption of FSP No. FIN 46(R)-6 did not have a material impact on Spectra Energy Capital’s consolidated results of operations, cash flows or financial position.
SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158). In October 2006, the FASB issued SFAS No. 158, which changes the recognition and disclosure provisions and measurement date requirements for an employer’s accounting for defined benefit pension and other postretirement plans. The recognition and disclosure provisions require an employer to (1) recognize the funded status of a benefit plan—measured as the difference between plan assets at fair value and the benefit obligation—in its statement of financial position, (2) recognize as a component of Other Comprehensive Income (OCI), net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost, and (3) disclose in the notes to financial statements certain additional information. SFAS No. 158 does not change the amounts recognized in the income statement as net periodic benefit cost. Spectra Energy Capital is required to initially recognize the funded status of its defined benefit pension and other postretirement plans and to provide the required additional disclosures as of December 31, 2006 (see Note 19). Retrospective application is not permitted. The adoption of SFAS No. 158 recognition and disclosure provisions resulted in an increase in total assets of approximately $21 million (consisting of an increase in deferred tax assets of $27 million, offset by a decrease in intangible assets of $6 million), an increase in total liabilities of approximately $69 million and an increase in accumulated other comprehensive income, net of tax, of approximately $48 million as of December 31, 2006. The adoption of SFAS No. 158 did not have any impact on Spectra Energy Capital’s consolidated results of operations or cash flows.
Under the measurement date requirements of SFAS No. 158, an employer is required to measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position (with limited exceptions). Historically, Spectra Energy Capital has measured its plan assets and obligations up to three months prior to the fiscal year-end, as allowed under the authoritative accounting literature. The measurement date requirement is effective for the year ending December 31, 2008, and early application is encouraged. Spectra Energy Capital intends to adopt the change in measurement date effective January 1, 2007 by remeasuring plan assets and benefit obligations as of that date, pursuant to the transition requirements of SFAS No. 158. Net periodic benefit cost for the three-month period between September 30, 2006 and December 31, 2006 will be recognized, net of tax, as a separate adjustment of retained earnings as of January 1, 2007. Additionally, changes in plan assets and plan obligations between September 30, 2006 and December 31, 2006 not related to net periodic benefit cost will be recognized, net of tax, as an adjustment to OCI.
SAB No. 108, “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements” (SAB No. 108). In September 2006 the SEC issued SAB No. 108, which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. Traditionally, there have been two widely-recognized approaches for quantifying the effects of financial statement misstatements. The income statement approach focuses primarily on the impact of a misstatement on the income statement—including the reversing effect of prior year misstatements—but its use can lead to the accumulation of misstatements in the balance sheet. The
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
balance sheet approach, on the other hand, focuses primarily on the effect of correcting the period-end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach (a “dual approach”) and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material.
SAB No. 108 was effective for Spectra Energy Capital’s year ended December 31, 2006. SAB No. 108 permits existing public companies to initially apply its provisions either by (i) restating prior financial statements as if the “dual approach” had always been used or (ii), under certain circumstances, recording the cumulative effect of initially applying the “dual approach” as adjustments to the carrying values of assets and liabilities as of January 1, 2006 with an offsetting adjustment recorded to the opening balance of retained earnings. Spectra Energy Capital has historically used a dual approach for quantifying identified financial statement misstatements. Therefore, the adoption of SAB No. 108 did not have any material impact on Spectra Energy Capital’s consolidated results of operations, cash flows or financial position.
The following new accounting standards were adopted by Spectra Energy Capital during the year ended December 31, 2005 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:
SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29” (SFAS No. 153). In December 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” 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 on or after July 1, 2005. The adoption of SFAS No. 153 did not have a material impact on Spectra Energy Capital’s consolidated results of operations, cash flows or financial position.
FASB Interpretation No. (FIN) 47 “Accounting for Conditional Asset Retirement Obligations”(FIN 47). In March 2005, the FASB issued FIN 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” (SFAS No. 143). A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 143 if the fair value of the liability can be reasonably estimated. The provisions of FIN 47 were effective for Spectra Energy Capital as of December 31, 2005, and resulted in an increase in assets of $7 million, an increase in liabilities of $11 million and a net-of-tax cumulative effect adjustment to earnings of approximately $4 million.
FASB Staff Position (FSP) No. APB 18-1, “Accounting by an Investor for Its Proportionate Share of Accumulated Other Comprehensive Income of an Investee Accounted for under the Equity Method in Accordance with APB Opinion No. 18 upon a Loss of Significant Influence” (FSP No. APB 18-1). In July 2005, the FASB staff issued FSP No. APB 18-1 which provides guidance for how an investor should account for its proportionate share of an investee’s equity adjustments for other comprehensive income (OCI) upon a loss of significant influence. APB Opinion No. 18 requires a transaction of an equity method investee of a capital nature be accounted for as if the investee were a consolidated subsidiary, which requires the investor to record its proportionate share of the investee’s adjustments for OCI as increases or decreases to the investment account with corresponding adjustments in equity. FSP No. APB 18-1 requires that an investor’s proportionate share of an investee’s equity adjustments for OCI should be offset against the carrying value of the investment at the time
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
significant influence is lost and equity method accounting is no longer appropriate. However, to the extent that the offset results in a carrying value of the investment that is less than zero, an investor should (a) reduce the carrying value of the investment to zero and (b) record the remaining balance in income. The guidance in FSP No. APB 18-1 was effective for Spectra Energy Capital beginning October 1, 2005. The adoption of FSP No. APB 18-1 did not have a material impact on Spectra Energy Capital’s consolidated results of operations, cash flows or financial position.
The following new accounting standards were adopted by Spectra Energy 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), “Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51” (FIN 46R), which supersedes and amends the provisions of FIN 46. While FIN 46R retains many of the concepts and provisions of FIN 46, it also provides additional guidance and additional scope exceptions, and incorporates FASB Staff Positions 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 Spectra Energy 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 Spectra Energy 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 Spectra Energy Capital).
Spectra Energy 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 an immaterial amount of total assets as of December 31, 2006 and 2005. The impact of consolidating these entities on Spectra Energy Capital’s consolidated financial statements was not material. In addition, at December 31, 2005, Spectra Energy Capital recorded Net Property, Plant and Equipment of $109 million and Long-term Debt of $173 million on the Consolidated Balance Sheets, associated with a natural gas processing variable interest entity that was consolidated by Spectra Energy Capital. In 2006, Spectra Energy Capital exercised its right to repurchase the assets held by the variable interest entity and repaid the loan.
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 Spectra Energy Capital’s Consolidated Financial Statements.
SFAS No. 132 (Revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (SFAS No. 132R). In December 2003, the FASB revised the provisions of SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an amendment of FASB Statements No. 87, 88, and 106,” 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 |
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
| • | 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 |
| • | 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 Spectra Energy 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 Spectra Energy Capital for the year ended December 31, 2004. (See Note 19 for the additional related disclosures).
FSP No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP No. FAS 106-2). In May 2004, the FASB staff issued FSP No. 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 No. 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 No. 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 No. FAS 106-2 were effective for the first interim period beginning after June 15, 2004. Spectra Energy Capital adopted FSP No. FAS 106-2 retroactively to the date of enactment of the Modernization Act, December 8, 2003, as allowed by the FSP. (See Note 19 for discussion of the effects of adopting this FSP).
FSP No. 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” (FSP No. FAS 109-1). 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 No. FAS 109-1, which was issued in December 2004, the deduction will be treated as a “special deduction” as described in SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109). As such, for Spectra Energy 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 is reported in the periods in which the deductions are claimed on the tax returns. For the years ended December 31, 2006 and 2005, Spectra Energy Capital recognized a benefit of approximately $0 and $9 million, respectively, relating to the deduction from qualified domestic activities.
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
FSP No. FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004” (FSP No. FAS 109-2). 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% dividends received deduction for certain dividends from controlled foreign corporations. FSP No. 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, Spectra Energy 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, Spectra Energy Capital has repatriated approximately $500 million in extraordinary dividends, as defined in the Act, and accordingly recorded a corresponding tax liability of $39 million as of December 31, 2005. However, Spectra Energy Capital has not provided for U.S. deferred income taxes or foreign withholding tax on basis differences for its non-U.S. subsidiaries that result primarily from undistributed earnings of approximately $25 million as of December 31, 2006 and $290 million as of December 31, 2005, which Spectra Energy Capital 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.
The following new accounting standards have been issued, but have not yet been adopted by Spectra Energy Capital as of December 31, 2006:
SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (SFAS No. 155). In February 2006, the FASB issued SFAS No. 155, which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for at fair value at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement (new basis) event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. SFAS No. 155 is effective for Spectra Energy Capital for all financial instruments acquired, issued, or subject to remeasurement after January 1, 2007, and for certain hybrid financial instruments that have been bifurcated prior to the effective date, for which the effect is to be reported as a cumulative-effect adjustment to beginning retained earnings. Spectra Energy Capital does not anticipate the adoption of SFAS No. 155 will have any material impact on its consolidated results of operations, cash flows or financial position.
SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements. However, in some cases, the application of SFAS No. 157 may change Spectra Energy Capital’s current practice for measuring and disclosing fair values under other accounting pronouncements that require or permit fair value measurements. For Spectra Energy Capital, SFAS No. 157 is effective as of January 1, 2008 and must be applied prospectively except in certain cases. Spectra Energy Capital is currently evaluating the impact of adopting SFAS No. 157, and cannot currently estimate the impact of SFAS No. 157 on its consolidated results of operations, cash flows or financial position.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS No. 159). In February 2007, the FASB issued SFAS No. 159, which permits entities to choose to measure many financial instruments and certain other items at fair value. For Spectra Energy Capital, SFAS No. 159 is effective as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. Spectra Energy Capital cannot currently estimate the impact of SFAS No. 159 on its consolidated results of operations, cash flows or financial position and has not yet determined whether or not it will choose to measure items subject to SFAS No. 159 at fair value.
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
FIN 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109.” In July 2006, the FASB issued FIN 48, which provides guidance on accounting for income tax positions about which Spectra Energy Capital has concluded there is a level of uncertainty with respect to the recognition in Spectra Energy Capital’s financial statements. FIN 48 prescribes a minimum recognition threshold a tax position is required to meet. Tax positions are defined very broadly and include not only tax deductions and credits but also decisions not to file in a particular jurisdiction, as well as the taxability of transactions. Spectra Energy Capital will implement FIN 48 effective January 1, 2007. The implementation is expected to result in a cumulative effect adjustment to beginning Member’s Equity on the Consolidated Statement of Member’s Equity and Comprehensive Income in the first quarter 2007 in the range of $15 million to $30 million. Corresponding entries will impact a variety of balance sheet line items, including Deferred income taxes, Taxes accrued and Other Liabilities. Upon implementation of FIN 48, Spectra Energy Capital will reflect interest expense related to taxes as Interest Expense, in the Consolidated Statement of Operations. In addition, subsequent accounting for FIN 48 (after January 1, 2007) will involve an evaluation to determine if any changes have occurred that would impact the existing uncertain tax positions as well as determining whether any new tax positions are uncertain. Any impacts resulting from the evaluation of existing uncertain tax positions or from the recognition of new uncertain tax positions would impact income tax expense and interest expense in the Consolidated Statement of Operations, with offsetting impacts to the balance sheet line items described above. Uncertain tax positions on consolidated or combined tax returns filed by Duke Energy which are indemnified by Spectra Energy will be recorded as payables to Duke Energy.
FSP No. FAS 123(R)-5, “Amendment of FASB Staff Position FAS 123(R)-1” (FSP No. FAS 123(R)-5). In October 2006, the FASB staff issued FSP No. FAS 123(R)-5 to address whether a modification of an instrument in connection with an equity restructuring should be considered a modification for purposes of applying FSP No. FAS 123(R)-1, “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R) (FSP No. FAS 123(R)-1).” In August 2005, the FASB staff issued FSP FAS 123(R)-1 to defer indefinitely the effective date of paragraphs A230—A232 of SFAS No. 123(R), and thereby require entities to apply the recognition and measurement provisions of SFAS No. 123(R) throughout the life of an instrument, unless the instrument is modified when the holder is no longer an employee. The recognition and measurement of an instrument that is modified when the holder is no longer an employee should be determined by other applicable generally accepted accounting principles. FSP No. FAS 123(R)-5 addresses modifications of stock-based awards made in connection with an equity restructuring and clarifies that for instruments that were originally issued as employee compensation and then modified, and that modification is made to the terms of the instrument solely to reflect an equity restructuring that occurs when the holders are no longer employees, no change in the recognition or the measurement (due to a change in classification) of those instruments will result if certain conditions are met. This FSP is effective for Spectra Energy Capital as of January 1, 2007. The impact to Spectra Energy Capital of applying FSP No. FAS 123(R)-5 in subsequent periods will be dependent upon the nature of any modifications to Spectra Energy Capital’s share-based compensation awards.
FSP No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” (FSP No. AUG AIR-1). In September 2006, the FASB Staff issued FSP No. AUG AIR-1. This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods, if no liability is required to be recorded for an asset retirement obligation based on a legal obligation for which the event obligating the entity has occurred. The FSP also requires disclosures regarding the method of accounting for planned major maintenance activities and the effects of implementing the FSP. The guidance in this FSP is effective for Spectra Energy Capital as of January 1, 2007 and will be applied retrospectively for all financial statements presented. Spectra Energy Capital does not anticipate the adoption of FSP No. AUG AIR-1 will have any material impact on its consolidated results of operations, cash flows or financial position.
87
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
2. Acquisitions and Dispositions
Acquisitions (excluding acquisitions made by discontinued operations that are discussed in Note 12). Spectra Energy 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 98-3, “Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business” (EITF 98-3), is recorded as goodwill. The allocation of the purchase price may be adjusted if additional, requested information is received during the allocation period, which generally does not exceed one year from the consummation date, however, it may be longer for certain income tax items.
In August 2005, Natural Gas Transmission acquired natural gas storage and pipeline assets in Southwest Virginia and an additional 50% interest in Saltville Gas Storage LLC (Saltville Storage) from units of AGL Resources for approximately $62 million. This transaction increased Natural Gas Transmission’s ownership percentage of Saltville Storage to 100%. No goodwill was recorded as a result of this acquisition.
In August 2005, Natural Gas Transmission acquired the Empress System natural gas processing and NGL marketing business from ConocoPhillips for approximately $230 million as part of the Field Services ConocoPhillips transaction discussed further in the Dispositions section below. No goodwill was recorded as a result of this acquisition.
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 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 DCP Midstream 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 Spectra Energy Capital recognizing a pre-tax impairment of approximately $13 million, which was approximately $4 million net of minority interest. 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 Onshore Gulf of Mexico. GC owns a 16.67% interest in two equity investments. DIGP owns gathering and transmission assets in the Offshore Gulf of Mexico.
The pro forma results of operations for Spectra Energy Capital as if those acquisitions which closed prior to December 31, 2006 occurred as of the beginning of the periods presented do not materially differ from reported results.
Dispositions. For the year ended December 31, 2006, the sale of other assets and businesses (which excludes discontinued operations that are discussed in Note 12) resulted in approximately $80 million in proceeds and net pre-tax gains of $47 million recorded in Gains (Losses) on Sales of Other Assets and Other, net on the Consolidated Statements of Operations. Significant sales of other assets during 2006 are detailed as follows:
| • | Natural Gas Transmission’s sale of certain Stone Mountain natural gas gathering system assets resulted in proceeds of $18 million (which is reflected in Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable within Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows), and pre-tax gain of $5 million which was |
88
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
recorded in Gains (Losses) on Sales of Other Assets and Other, net in the accompanying Consolidated Statements of Operations. In addition, Natural Gas Transmission’s sale of stock, received as consideration for the settlement of a customer’s transportation contract, resulted in proceeds of approximately $29 million (which is reflected in Other, assets within Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows) and a pre-tax gain of $29 million, of which approximately $28 million was recorded in Gains (Losses) on Sales of Other Assets and Other, net and approximately $1 million was recorded in Other Income and Expenses, net in the accompanying Consolidated Statements of Operations (see Note 8). |
| • | As a result of a settlement of a property insurance claim, Natural Gas Transmission received proceeds of approximately $30 million and recognized a pre-tax gain of approximately $10 million, which was recorded in Gains (Losses) on Sales of Other Assets and Other, net, in the Consolidated Statements of Operations. |
For the year ended December 31, 2005, the sale of other assets, businesses and equity investments (which excludes assets held for sale as of December 31, 2005 and discontinued operations, both of which are discussed in Note 12) resulted in approximately $2.3 billion in proceeds, pre-tax gains of $522 million recorded in Gains (Losses) on Sales of Other Assets and Other, net, on the accompanying Consolidated Statements of Operations and pre-tax gains of $1.2 billion recorded in (Losses) Gains on Sales and Impairments of Equity Method Investments on the accompanying Consolidated Statements of Operations. Significant sales of other assets and equity investments during 2005 are detailed as follows:
| • | In February 2005, DCP Midstream sold its wholly owned subsidiary Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP (TEPPCO LP), for approximately $1.1 billion and Spectra Energy Capital sold its limited partner interest in TEPPCO LP for approximately $100 million, in each case to Enterprise GP Holdings LP (EPCO), an unrelated third party. These transactions resulted in pre-tax gains of $1.2 billion, which were recorded in (Losses) Gains on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations. Minority Interest Expense of $343 million was recorded in the accompanying Consolidated Statements of Operations to reflect ConocoPhillips’ proportionate share in the pre-tax gain on sale of TEPPCO GP. Additionally, in July 2005, Spectra Energy Capital completed the agreement with ConocoPhillips, Spectra Energy Capital’s co-equity owner in DCP Midstream, to reduce Spectra Energy Capital’s ownership interest in DCP Midstream from 69.7% to 50% (the DCP Midstream disposition transaction), which results in Spectra Energy Capital and ConocoPhillips becoming equal 50% owners in DCP Midstream. Spectra Energy Capital has received, directly and indirectly through its ownership interest in DCP Midstream, a total of approximately $1.1 billion from ConocoPhillips and DCP Midstream, consisting of approximately $1.0 billion in cash and approximately $0.1 billion of assets. The DCP Midstream disposition transaction resulted in a pre-tax gain of approximately $575 million, which was recorded in Gains (Losses) on Sales of Other Assets and Other, net, in the accompanying Consolidated Statements of Operations. The DCP Midstream disposition transaction includes the transfer to Spectra Energy Capital of DCP Midstream’ Canadian natural gas gathering and processing facilities. Additionally, the DCP Midstream disposition transaction included the acquisition of ConocoPhillips’ interest in the Empress System. Subsequent to the closing of the DCP Midstream disposition transaction, effective on July 1, 2005, DCP Midstream is no longer consolidated into Spectra Energy Capital’s consolidated financial statements and is accounted for by Spectra Energy Capital as an equity method investment. See Note 7 for the impacts of this transaction on certain cash flow hedges. The Canadian natural gas gathering and processing facilities and the Empress System are included in the Natural Gas Transmission segment. |
| • | In December 2005, the Income Fund, a Canadian income trust fund, was created to acquire all of the common shares of Spectra Energy Capital Midstream Services Canada Corporation (Spectra Midstream) from a subsidiary of Spectra Energy Capital. The Income Fund sold an approximate 40% ownership interest in Spectra Midstream for approximately $110 million, which was included in Proceeds from Spectra Energy Income Fund within Cash Flows from Financing activities on the |
89
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Consolidated Statements of Cash Flows. In January 2006, a subsequent greenshoe sale of additional ownership interests, pursuant to an overallotment option, in the Income Fund were sold for approximately $10 million. Spectra Energy Capital retains an ownership interest in the Income Fund of approximately 58% and will continue to operate and manage this business. Spectra Energy Capital continues to consolidate the results of this business. |
| • | In December 2005, Commercial Power recorded a $70 million charge related to the termination of structured power contracts in the Southeast, which was recorded in Gains (Losses) on Sales of Other Assets and Other, net on the accompanying Consolidated Statements of Operations. |
For the year ended December 31, 2004, the sale of other assets and businesses (which excludes discontinued operations, which is discussed in Note 12) resulted in approximately $466 million in cash proceeds plus a $48 million note receivable from the buyers, and net pre-tax losses of $349 million recorded in Gains (Losses) on Sales of Other Assets and Other, net and pre-tax losses of $5 million recorded in (Losses) Gains on Sales and Impairments of Equity Method Investments on the Consolidated Statements of Operations. (Losses) Gains on Sales and Impairments of Equity Method Investments included 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 Gains (Losses) on Sales of Other Assets and Other, net and $16 million was recorded in (Losses) Gains on Sales and Impairments of Equity Method 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 Gains (Losses) on Sales of Other Assets and Other, net in the Consolidated Statements of Operations. These sales consisted of multiple small sales. |
| • | Commercial Power’s asset sales totaled approximately $420 million in net proceeds and a $48 million note receivable. Those sales resulted in pre-tax losses of $360 million which were recorded in Gains (Losses) on Sales of Other Assets and Other, net in the Consolidated Statements of Operations. |
| • | Commercial Power sold eight natural gas-fired merchant power plants in the Southeastern United States and certain other power and gas contracts (collectively, the Southeast Plants). Spectra Energy 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. 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 Gains (Losses) on Sales of Other Assets and Other, net in the 2004 Consolidated Statement of Operations. 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 sales price consisted of $420 million of cash and a $48 million note receivable from KGen that was repaid in full during 2005. |
Spectra Energy Capital retained certain guarantees related to the sold assets. In conjunction with the sale, Spectra Energy 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. Spectra Energy Capital is the ultimate obligor to the letter of credit provider, but KGen has an obligation to reimburse Spectra Energy Capital for any payments made by it under the letter of credit, as well as expenses incurred by Spectra Energy Capital in connection with the letter of credit. During the fourth quarter of 2006, Spectra Energy Capital assigned the letter of credit and guarantee to Duke Energy. As a result of Spectra Energy Capital’s significant continuing involvement in the operations of the plants at the time of the sale this transaction did not qualify for discontinued operations presentation, as
90
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
prescribed by SFAS No. 144. However, this continuing involvement did not prohibit sale accounting under SFAS No. 66, “Accounting for Sales of Real Estate.” There were no remaining operations or obligations retained by Spectra Energy Capital subsequent to the separation from Duke Energy.
See Note 12 for discussion of businesses acquired or disposed of during the years ended December 31, 2006, 2005 and 2004 that were included in the operations transferred to Duke Energy during 2006 and, accordingly, are included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.
SAB 51 Gain. In September 2006, the Income Fund created in 2005 sold approximately 9 million previously unissued Trust Units for total proceeds of $94 million, net of commissions and other expenses of issuance, which is included in Proceeds from Spectra Energy Income Fund within Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows. The sale of these units reduced Spectra Energy Capital’s ownership interest in the businesses of the Income Fund to approximately 46% at December 31, 2006. As a result of the sale of additional Trust Units, Spectra Energy Capital recognized an approximate $15 million pre-tax SAB No. 51 gain on the sale of subsidiary stock, which is classified in Gain on Sale of Subsidiary Stock on the Consolidated Statements of Operations. The proceeds from the offering plus the draw down of approximately 39 million Canadian dollars on an available credit facility were used by the Income Fund to acquire a 100% interest in Westcoast Gas Services, Inc. from Spectra Energy Capital. There were no deferred taxes recorded as a result of this transaction.
3. Business Segments
In conjunction with Duke Energy’s merger with Cinergy, effective with the second quarter ended June 30, 2006, Spectra Energy Capital adopted new business segments that management believed properly aligned the various operations of Spectra Energy Capital with how the chief operating decision maker viewed the business. Prior to the December 2006 transfer to Duke Energy of International Energy, the 50% interest in Crescent and certain businesses included in Other (see Note 1), both International Energy and Crescent were business segments of Spectra Energy Capital. At December 31, 2006, Spectra Energy Capital reported the following business segments: Natural Gas Transmission and Field Services. Commercial Power has no assets or operations within Spectra Energy Capital as of December 31, 2006. Spectra Energy Capital’s chief operating decision maker regularly reviewed financial information about each of these business segments in deciding how to allocate resources and evaluate performance. All of the Spectra Energy Capital’s business segments are considered reportable segments under SFAS No. 131. There is no aggregation within Spectra Energy Capital’s defined business segments.
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, natural gas processing services to customers in Western Canada and other energy related services. The 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 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). Natural Gas Transmission also includes the results of operations of the McMahon facility and the Canadian gathering and processing facilities transferred to Natural Gas Transmission from DENA and Field Services, respectively, during 2005.
Field Services gathers, compresses, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, gathers, treats, processes, trades and markets, and stores NGLs. It conducts operations primarily through DCP Midstream, which is owned 50% by ConocoPhillips and 50% by Spectra Energy Capital. Field Services gathers raw natural gas through gathering systems located in seven major natural gas producing regions: Permian, Mid-Continent, East Texas-North Louisiana, South, Central, Rocky Mountain and Gulf Coast.
91
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
In February 2005, DCP Midstream sold its wholly owned subsidiary TEPPCO GP, which is the general partner of TEPPCO LP, and Spectra Energy Capital sold its limited partner interest in TEPPCO LP, in each case to EPCO, an unrelated third party. As a result of the DCP Midstream disposition transaction discussed in Note 2, Spectra Energy Capital deconsolidated its investment in DCP Midstream effective July 1, 2005 and subsequently has accounted for it as an investment utilizing the equity method of accounting. In connection with the DCP Midstream disposition transaction, DCP Midstream transferred its Canadian natural gas gathering and processing facilities to the Natural Gas Transmission segment.
Commercial Power, which did not have any operations or net assets within Spectra Energy Capital as of and for the year ended December 31, 2006, consisted of a portion of Spectra Energy Capital’s operations formerly known as DENA. Commercial Power operated and managed power plants and related contractual positions in the Southeastern United States. Commercial Power’s continuing operations consisted primarily of eight natural gas-fired merchant power plants in the Southeastern United States and certain other power and gas contracts (collectively, the “Southeast Plants”) Spectra Energy Capital sold the Southeast Plants in August 2004 and the remaining contracts in 2005, and remains reported as a business segment in 2005 and 2004 as a result of continuing involvement identified at the time of the sale.
The remainder of Spectra Energy Capital’s operations is presented as “Other”. While it is not considered a business segment, Other primarily includes the following:
| • | Certain unallocated corporate costs, certain discontinued hedges and Bison, Spectra Energy Capital’s wholly owned, captive insurance subsidiary. As discussed in Note 1, on April 1, 2006, Spectra Energy Capital transferred the operations of Bison to Duke Energy. However, the results of operations of Bison do not qualify for discontinued operations treatment for the periods prior to the transfer due to continuing involvement with Bison and as a result of Spectra Energy Capital’s creation of a captive insurance subsidiary effective with the spin-off. Bison’s principal 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 Spectra Energy Capital. Bison also participates in reinsurance activities with certain third parties, on a limited basis. |
Spectra Energy Capital’s reportable segments offer different products and services and are managed separately as business units. Accounting policies for Spectra Energy Capital’s segments are the same as those described in Note 1. Management evaluates segment performance 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 Spectra Energy Capital, so the associated realized and unrealized gains and losses from foreign currency transactions 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.
92
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Business Segment Data(a)
| Unaffiliated Revenues | Intersegment Revenues | Total Revenues | Segment EBIT/ Consolidated Earnings from Continuing Operations before Income Taxes | Depreciation and Amortization(b) | Capital and Investment Expenditures(b) | Segment Assets(c) | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||
Year Ended December 31, 2006 | |||||||||||||||||||||||||
Natural Gas Transmission | $ | 4,546 | $ | (23 | ) | $ | 4,523 | $ | 1,438 | $ | 480 | $ | 790 | $ | 18,998 | ||||||||||
Field Services(f) | — | — | — | 569 | — | — | 1,233 | ||||||||||||||||||
Total reportable segments | 4,546 | (23 | ) | 4,523 | 2,007 | 480 | 790 | 20,231 | |||||||||||||||||
Other | (14 | ) | 44 | 30 | (89 | ) | 9 | 40 | 91 | ||||||||||||||||
Eliminations and reclassifications | — | (21 | ) | (21 | ) | — | — | — | 23 | ||||||||||||||||
Interest expense | — | — | — | (605 | ) | — | — | — | |||||||||||||||||
Interest income and other(d) | — | — | — | 18 | — | — | — | ||||||||||||||||||
Total consolidated | $ | 4,532 | $ | — | $ | 4,532 | $ | 1,331 | $ | 489 | $ | 830 | $ | 20,345 | |||||||||||
Year Ended December 31, 2005 | |||||||||||||||||||||||||
Natural Gas Transmission | $ | 3,990 | $ | 65 | $ | 4,055 | $ | 1,388 | $ | 458 | $ | 930 | $ | 18,823 | |||||||||||
Field Services(f) | 5,618 | (88 | ) | 5,530 | 1,946 | 143 | 86 | 1,377 | |||||||||||||||||
Commercial Power(e) | — | — | — | (70 | ) | — | — | 1,619 | |||||||||||||||||
International Energy | — | — | — | — | — | — | 2,962 | ||||||||||||||||||
Crescent | — | — | — | — | — | — | 1,507 | ||||||||||||||||||
Total reportable segments | 9,608 | (23 | ) | 9,585 | 3,264 | 601 | 1,016 | 26,288 | |||||||||||||||||
Other(e) | (154 | ) | 150 | (4 | ) | (278 | ) | 10 | 18 | 8,533 | |||||||||||||||
Eliminations and reclassifications | — | (127 | ) | (127 | ) | — | — | — | 235 | ||||||||||||||||
Interest expense | — | — | — | (675 | ) | — | — | — | |||||||||||||||||
Interest income and other(d) | — | — | — | 24 | — | — | — | ||||||||||||||||||
Total consolidated | $ | 9,454 | $ | — | $ | 9,454 | $ | 2,335 | $ | 611 | $ | 1,034 | $ | 35,056 | |||||||||||
Year Ended December 31, 2004 | |||||||||||||||||||||||||
Natural Gas Transmission | $ | 3,277 | $ | 74 | $ | 3,351 | $ | 1,329 | $ | 431 | $ | 544 | $ | 17,783 | |||||||||||
Field Services(f) | 9,998 | 46 | 10,044 | 367 | 285 | 202 | 6,265 | ||||||||||||||||||
Commercial Power(e) | 113 | — | 113 | (386 | ) | 8 | 6 | 1,646 | |||||||||||||||||
International Energy | — | — | — | — | — | — | 3,058 | ||||||||||||||||||
Crescent | — | — | — | — | — | — | 1,317 | ||||||||||||||||||
Total reportable segments | 13,388 | 120 | 13,508 | 1,310 | 724 | 752 | 30,069 | ||||||||||||||||||
Other(e) | 46 | 65 | 111 | 48 | 9 | 23 | 6,968 | ||||||||||||||||||
Eliminations and reclassifications | (1 | ) | (185 | ) | (186 | ) | — | — | — | 146 | |||||||||||||||
Interest expense | — | — | — | (858 | ) | — | — | — | |||||||||||||||||
Interest income and other(d) | — | — | — | 61 | — | — | — | ||||||||||||||||||
Total consolidated | $ | 13,433 | $ | — | $ | 13,433 | $ | 561 | $ | 733 | $ | 775 | $ | 37,183 | |||||||||||
93
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
| (a) | Segment results exclude results of entities classified as discontinued operations. |
| (b) | Excludes amounts associated with entities included in discontinued operations. |
| (c) | Includes assets held for sale. |
| (d) | Other includes foreign currency transaction gains and losses, and additional minority interest expense not allocated to the segment results. |
| (e) | Amounts associated with former DENA operations are included in Other for all periods presented, except for the Southeast operations, which are reflected in Commercial Power. Asset amounts for Commercial Power primarily include the assets of the Midwestern generation that were transferred to Duke Energy in April 2006. |
| (f) | In July 2005, Duke Energy caused a Spectra Energy Capital subsidiary to complete the agreement with ConocoPhillips to reduce Spectra Energy Capital’s ownership interest in DCP Midstream from 69.7% to 50%. Field Services segment data includes DCP Midstream as a consolidated entity for periods prior to July 1, 2005 and as an equity method investment for periods after June 30, 2005. |
Geographic Data
| U.S. | Canada | Other Foreign | Consolidated | |||||||||
| (in millions) | ||||||||||||
2006 | ||||||||||||
Consolidated revenues(a) | $ | 1,381 | $ | 3,141 | $ | 10 | $ | 4,532 | ||||
Consolidated long-lived assets | 6,519 | 10,525 | — | 17,044 | ||||||||
2005 | ||||||||||||
Consolidated revenues(a) | $ | 6,706 | $ | 2,710 | $ | 38 | $ | 9,454 | ||||
Consolidated long-lived assets | 15,189 | 10,542 | 2,344 | 28,075 | ||||||||
2004 | ||||||||||||
Consolidated revenues(a) | $ | 11,318 | $ | 2,066 | $ | 49 | $ | 13,433 | ||||
Consolidated long-lived assets | 17,532 | 9,874 | 2,227 | 29,633 | ||||||||
| (a) | Excludes revenues associated with businesses included in discontinued operations. |
94
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
4. Regulatory Matters
Regulatory Assets and Liabilities. Spectra Energy Capital’s regulated operations are subject to SFAS No. 71. Accordingly, Spectra Energy 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.)
Regulatory Assets and Liabilities:
| As of December 31, | Recovery/Refund Period Ends | |||||||
| 2006 | 2005 | |||||||
| (in millions) | ||||||||
Regulatory Assets(a) | ||||||||
Net regulatory asset related to income taxes(b) | $ | 848 | $ | 954 | (g) | |||
Project costs(c) | 37 | 40 | 2024 | |||||
Hedge costs and other deferrals(c) | 31 | — | 2007 | |||||
Vacation accrual(c) | 17 | 9 | 2007 | |||||
Deferred debt expense(d) | 11 | 14 | 2011 | |||||
Environmental clean-up costs(c) | 6 | 7 | 2017 | |||||
Gas purchase costs(c) | — | 34 | 2006 | |||||
Other(c) | 9 | 5 | (i) | |||||
Total Regulatory Assets | $ | 959 | $ | 1,063 | ||||
Regulatory Liabilities(a) | ||||||||
Removal costs(d)(f) | $ | 329 | $ | 350 | (h) | |||
Gas purchase costs(e) | 166 | — | 2007 | |||||
Pipeline rate credit(f) | 36 | 37 | 2041 | |||||
Storage and transportation liability(e) | 15 | 9 | 2007 | |||||
Earnings sharing liability(e) | 12 | 9 | 2007 | |||||
Other deferred tax credits(d)(f) | 5 | 8 | (i) | |||||
Other(f) | 6 | 7 | 2007 | |||||
Total Regulatory Liabilities | $ | 569 | $ | 420 | ||||
| (a) | All regulatory assets and liabilities are excluded from rate base unless otherwise noted. |
| (b) | All amounts are expected to be included in future rate filings. |
| (c) | Included in Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets. |
| (d) | Included in rate base. |
| (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) | Liability is extinguished over the lives of the associated assets. |
| (i) | Recovery/Refund period currently unknown. |
95
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Rate Related Information.
Maritimes & Northeast Pipeline L.L.C. Effective January 1, 2005, new rates for Maritimes & Northeast Pipeline L.L.C. took effect, subject to refund, as a result of a rate case filed in 2004. On May 15, 2006, the FERC issued an order approving a settlement agreement that provides for a rate increase over rates charged prior to January 1, 2005. In June 2006, the difference between the settlement rates and the interim rates, plus interest, was refunded to applicable shippers. There was no material impact to Spectra Energy Capital’s consolidated results of operations as a result of the refund.
Maritimes & Northeast Pipeline, L.P. In 2006, Maritimes & Northeast Pipeline, L.P., operated under an NEB-approved toll settlement that expired December 31, 2006. A toll settlement agreement for the 2007 fiscal year was approved by the NEB on December 14, 2006.
Algonquin Gas Transmission LLC (Algonquin). In April 2005, Algonquin filed and the FERC accepted new negotiated rate agreements with the Algonquin customers that include a rate moratorium provision through December 2008.
Gulfstream Natural Gas System, LLC (Gulfstream). In September 2005, FERC approved Gulfstream’s Cost and Revenue study that was required to be filed as a condition in its Phase I and Phase II expansion projects. Gulfstream is not anticipated to have further filing requirements until three years after its Phase III expansion facilities are placed into service, currently expected in 2008.
East Tennessee Natural Gas, LLC (East Tennessee). On November 1, 2005, East Tennessee placed into effect new rates approved by FERC as a result of a rate settlement with customers. The settlement agreement includes a five year rate moratorium and certain operational changes. On December 14, 2006, East Tennessee filed to establish system-wide segmentation on part of its system, subject to FERC approval. This filing was generally supported by the customers, and is proposed to be implemented effective November 1, 2007.
Texas Eastern Transmission, L.P. (Texas Eastern). Texas Eastern continues to operate under rates approved by FERC in 1998 in an uncontested settlement between Texas Eastern and its customers.
Union Gas Limited (Union Gas). Union Gas has rates that are approved by the OEB. Effective January 1, 2006, Union Gas implemented new rates approved by the OEB in December 2005. Union’s earnings for 2006 continued to be subject to the earnings sharing mechanism implemented by the OEB in 2005. Earnings in 2006 above an allowable rate of return on equity, normalized for weather, may be shared equally between ratepayers and Union Gas. Union Gas expects to apply to the OEB for the disposition of the earnings sharing amount, as well as other non-commodity deferral account balances, during the second quarter of 2007.
On August 25, 2006, the OEB issued a decision on certain common issues related to the Demand Side Management (DSM) activities of Union Gas and Enbridge Gas Distribution. Most of the issues were the subject of a settlement agreement with intervenors. In that decision, the OEB accepted a formulaic approach to establishing annual DSM savings targets, budgets and utility incentives for a three-year plan term effective January 1, 2007. The result of this decision is an increase to the DSM budget and an opportunity to earn in excess of $4 million annually if the DSM savings target is achieved or exceeded. Union Gas has subsequently applied to the OEB for approval of its 2007 DSM programs, which it received on January 26, 2007.
On November 7, 2006, Union Gas received a decision from the OEB on the regulation of rates for gas storage services in Ontario. As a result of its finding that the market for storage services is competitive, the OEB will not regulate the rates for storage services to customers outside Union Gas’ franchise area or the rates for new storage services to customers within its franchise area. Existing storage services to customers within Union Gas’ franchise area will continue to be provided at regulated cost-based rates. Since the issuance of the decision, five parties who participated in the storage regulation proceeding have appealed various aspects of the decision to the OEB. The OEB heard submissions during a hearing held March 5 and March 6, 2007 regarding whether those parties have met the threshold for an appeal review. The OEB’s decision is expected in 2007.
96
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
In December 2006, the OEB issued a final rate order for new rates effective January 1, 2007, reflecting the outcomes from the Union Gas’ 2007 rate application, the DSM proceeding and the storage regulation decision. The average rate increase is approximately 3.1% and includes the impact of an increase in the common equity component of Union’s capital structure from 35% to 36% and a decrease in the allowed return on equity from 9.63% to 8.54%.
BC Pipeline and Field Services. BC Pipeline reached a settlement agreement with its customers for the 2006 and 2007 fiscal years on March 30, 2006. This agreement was approved by the NEB on August 17, 2006. On December 24, 2006, BC Pipeline filed an application with the NEB for approval of 2007 interim transportation tolls until such time as the final 2007 transportation tolls are approved. On March 15, 2007, the NEB approved the recovery of certain costs associated with the Southern Mainline expansion project and an application for the approval of final 2007 transportation tolls was filed on March 19, 2007.
The BC Pipeline and Field Services businesses in Western Canada recorded regulatory assets related to deferred income tax liabilities of approximately $570 million as of December 31, 2006 and $640 million as of December 31, 2005. 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 Pipelines’ and 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 Field Services businesses. Based on current evaluation of these factors, management believes that recovery of these tax costs is probable over the periods described above.
Management believes that the effects of the above matters will have no material adverse effect on Spectra Energy Capital’s future consolidated results of operations, cash flows or financial position.
97
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
5. Income Taxes
The following details the components of income tax expense (benefit):
Income Tax Expense
| For the Years Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (in millions) | ||||||||||||
Current income taxes | ||||||||||||
Federal | $ | 270 | $ | 869 | $ | 80 | ||||||
State | (35 | ) | 80 | 29 | ||||||||
Foreign | 129 | 42 | 50 | |||||||||
Total current income taxes | 364 | 991 | 159 | |||||||||
Deferred income taxes | ||||||||||||
Federal | 83 | (82 | ) | 1,024 | ||||||||
State | (22 | ) | (15 | ) | 65 | |||||||
Foreign | (30 | ) | 32 | 20 | ||||||||
Total deferred income taxes | 31 | (65 | ) | 1,109 | ||||||||
Total income tax expense from continuing operations | 395 | 926 | 1,268 | |||||||||
Total income tax expense (benefit) from discontinued operations | 61 | 104 | (55 | ) | ||||||||
Total income tax benefit from cumulative effect of change in accounting principle | — | (1 | ) | — | ||||||||
Total income tax expense presented in Consolidated Statements of Operations | $ | 456 | $ | 1,029 | $ | 1,213 | ||||||
Earnings from Continuing Operations before Income Taxes
| For the Years Ended December 31, | |||||||||
| 2006 | 2005 | 2004 | |||||||
| (in millions) | |||||||||
Domestic | $ | 945 | $ | 2,031 | $ | 278 | |||
Foreign | 386 | 304 | 283 | ||||||
Total earnings from continuing operations before income taxes | $ | 1,331 | $ | 2,335 | $ | 561 | |||
Reconciliation of Income Tax Expense at the U.S. Federal Statutory Tax Rate to the Actual Tax Expense from Continuing Operations (Statutory Rate Reconciliation)
| For the Years Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (in millions) | ||||||||||||
Income tax expense, computed at the statutory rate of 35% | $ | 466 | $ | 817 | $ | 196 | ||||||
State income tax, net of federal income tax effect | (37 | ) | 42 | 61 | ||||||||
Tax differential on foreign earnings | (36 | ) | (32 | ) | (32 | ) | ||||||
Pass-through of income tax expense(a) | 26 | 81 | 48 | |||||||||
Deferred taxes on restructuring of certain subsidiaries | — | — | 991 | |||||||||
Impairment of Bolivian investment | (25 | ) | — | — | ||||||||
U.S. tax on repatriation of foreign earnings | — | 34 | — | |||||||||
Other items, net | 1 | (16 | ) | 4 | ||||||||
Total income tax expense from continuing operations | $ | 395 | $ | 926 | $ | 1,268 | ||||||
Effective tax rate | 29.7 | % | 39.7 | % | 226.0 | % | ||||||
| (a) | Prior to the effective date of the tax sharing agreement with Duke Energy, tax expenses and benefits were passed through to Duke Energy. |
98
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
During 2006 Spectra Energy Capital recorded an approximate $30 million benefit to state taxes due to a reduction in the unitary state tax rate in 2006 as a result of Duke Energy’s merger with Cinergy. This $30 million benefit is included in “State income tax, net of federal income tax effect.” Additionally, Spectra Energy Capital recognized a tax benefit related to the impairment of an investment in Bolivia, which is included in “Impairment of Bolivian investment”, which is included in continuing operations due to a change in tax status.
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, DEA, a directly wholly owned subsidiary of Spectra Energy Capital. DEA and Spectra Energy Capital are pass-through entities for U.S. income tax purposes. Spectra Energy Capital recognized federal and state tax expense of approximately $1,030 million in continuing operations during 2004 from this reorganization.
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”.
Net Deferred Income Tax Liability Components
| December 31, | ||||||||
| 2006 | 2005 | |||||||
| (in millions) | ||||||||
Deferred credits and other liabilities | $ | 133 | $ | 415 | ||||
Other | 17 | 27 | ||||||
Total deferred income tax assets | 150 | 442 | ||||||
Valuation allowance | (13 | ) | (26 | ) | ||||
Net deferred income tax assets | 137 | 416 | ||||||
Investments and other assets | (1,387 | ) | (893 | ) | ||||
Accelerated depreciation rates | (636 | ) | (1,386 | ) | ||||
Regulatory assets and deferred debits | (1,033 | ) | (1,097 | ) | ||||
Total deferred income tax liabilities | (3,056 | ) | (3,376 | ) | ||||
Total net deferred income tax liabilities | $ | (2,919 | ) | $ | (2,960 | ) | ||
The above amounts have been classified in the Consolidated Balance Sheets as follows:
| December 31, | ||||||||
| 2006 | 2005 | |||||||
| (in millions) | ||||||||
Current deferred tax assets, included in other current assets | $ | 96 | $ | — | ||||
Non-current deferred tax assets, included in other investments and other assets | 5 | 254 | ||||||
Current deferred tax liabilities, included in other current liabilities | (40 | ) | (47 | ) | ||||
Non-current deferred tax liabilities | (2,980 | ) | (3,167 | ) | ||||
Total net deferred income tax liabilities | $ | (2,919 | ) | $ | (2,960 | ) | ||
Although the outcome of tax audits is uncertain, management believes that adequate provisions for income and other taxes, such as sales and use, franchise, and property, have been made for potential liabilities resulting from such matters. As of the year ended December 31, 2006, Spectra Energy Capital has total provisions, including interest, of approximately $85 million for uncertain tax positions, as compared to $125 million as of December 31, 2005. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on Spectra Energy Capital’s consolidated results of operations, cash flows or financial position.
99
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
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.
On October 22, 2004, the President of the United States signed the American Jobs Creation Act of 2004 (the Act), which provides a deduction for income from qualified domestic production activities, which will be phased in from 2005 to 2010.
Under the guidance in FSP No. FAS 109-1, which was issued in December 2004, the deduction is treated as a “special deduction” as described in SFAS No. 109. As such, for Spectra Energy Capital, the special deduction had no material impact on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this special deduction will be reported in the periods in which the deductions are claimed on the tax returns. For the year ended December 31, 2006, Spectra Energy Capital recognized a benefit of approximately $5 million relating to the deduction from qualified domestic activities.
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% dividends received deduction for certain dividends from controlled foreign corporations. FSP No. 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. During 2004, Duke Energy recorded a $45 million income tax expense for the repatriation of approximately $500 million of foreign earnings that was 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 Spectra Energy Capital. During this repatriation process, Duke Energy reorganized various entities and reestimated its liability which enabled it to reduce the $45 million tax liability to a $39 million tax liability. This reorganization also caused Spectra Energy Capital to increase the $5 million tax liability to a $39 million tax liability as of December 31, 2005. Spectra Energy Capital had paid off this $39 million tax liability to the respective jurisdictions as of December 31, 2005. (See rate reconciliation above)
Deferred income taxes and foreign withholding taxes have not been provided on the remaining undistributed earnings of Spectra Energy Capital’s foreign subsidiaries as such amounts are deemed to be permanently reinvested. The cumulative undistributed earnings as of December 31, 2006 on which Spectra Energy Capital has not provided deferred income taxes and foreign withholding taxes, is approximately $25 million.
6. Asset Retirement Obligations
In June 2001, the FASB issued SFAS No. 143, which was adopted by Spectra Energy Capital on January 1, 2003 and 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. 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. Subsequent to the initial recognition, the liability is adjusted for any revisions to the expected value of the retirement obligation (with corresponding adjustments to property, plant, and equipment), and for accretion of the liability due to the passage of time. Additional depreciation expense is recorded prospectively for any property, plant and equipment increases.
Asset retirement obligations at Spectra Energy Capital relate primarily to the retirement of certain gathering pipelines and processing facilities, obligations related to right-of-way agreements, and contractual leases for land use. In accordance with SFAS No. 143, Spectra Energy Capital determined that a significant portion of its assets
100
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
have an indeterminate life, and thus the fair value of the retirement obligation is not reasonably estimable. These assets included on-shore and some off-shore pipelines, and certain processing plants and distribution facilities. A liability for these asset retirement obligations will be recorded when a fair value is determinable.
Upon adoption of SFAS No. 143, Spectra Energy 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 under SFAS No. 71. Spectra Energy Capital does not accrue the estimated cost of removal when no legal obligation associated with retirement or removal exists for any of its non-regulated assets. The total amount of removal costs included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets was $329 million and $350 million as of December 31, 2006 and 2005, respectively.
As a result of the adoption of FIN 47 in 2005, net property, plant and equipment increased $7 million and ARO liabilities increased $11 million. A net-of-tax cumulative effect adjustment of approximately $4 million was recorded in the fourth quarter of 2005 as a reduction in earnings (see Note 1).
The pro forma effects of adopting FIN 47, including the impact on the balance sheet and net income are not presented due to the 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
| Years Ended December 31, | |||||||
| 2006 | 2005 | ||||||
| (in millions) | |||||||
Balance as of January 1, | $ | 29 | $ | 62 | |||
Liabilities settled(a) | — | (46 | ) | ||||
Accretion expense | 2 | 1 | |||||
Revisions in estimated cash flows(b) | 54 | 1 | |||||
Adoption of FIN 47 | — | 11 | |||||
Balance as of December 31,(c) | $ | 85 | $ | 29 | |||
| (a) | Primarily represents a decrease in ARO liabilities during 2005 due to the deconsolidation of DCP Midstream on July 1, 2005. |
| (b) | ARO estimate revised as a result of a detailed study conducted during 2006 by an industry expert on historical experience with abandonments. |
| (c) | Amounts included in Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets |
7. Risk Management and Hedging Activities, Credit Risk, and Financial Instruments
Spectra Energy Capital is exposed to the impact of market fluctuations in the prices of NGLs, natural gas and other energy-related products marketed and purchased as a result of its investment in DCP Midstream and ownership of energy related assets. Exposure to interest rate risk exists as a result of the issuance of variable and fixed rate debt and commercial paper. Spectra Energy 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. Spectra Energy Capital employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including swaps, futures, forwards and options.
101
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Spectra Energy Capital’s Derivative Portfolio Carrying Value as of December 31, 2006
Asset/(Liability) | Maturity in 2007 | Maturity in 2008 | Maturity in 2009 | Maturity in 2010 and Thereafter | Total Carrying Value | ||||||||||||||
| (in millions) | |||||||||||||||||||
Hedging | $ | — | $ | — | $ | 17 | $ | (4 | ) | $ | 13 | ||||||||
Undesignated | (7 | ) | (1 | ) | — | (8 | ) | (16 | ) | ||||||||||
Total | $ | (7 | ) | $ | (1 | ) | $ | 17 | $ | (12 | ) | $ | (3 | ) | |||||
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 Spectra Energy Capital’s Consolidated Balance Sheets.
As a result of the transfer of 19.7% interest in DCP Midstream to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DCP Midstream (see Note 2), Spectra Energy Capital discontinued hedge accounting for certain contracts held by Spectra Energy Capital related to Field Services’ commodity price risk, which were previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and have been retained as undesignated derivatives. Since discontinuance of hedge accounting, these contracts have been marked-to-market in the Consolidated Statements of Operations. As a result, approximately $19 million and $314 million of realized and unrealized pre-tax losses related to these contracts were recognized in earnings by Spectra Energy Capital for the years ended December 31, 2006 and December 31, 2005, respectively. All the 2006 charges have been classified in the accompanying Consolidated Statements of Operations as a component of Other Income and Expenses. The 2005 charges were classified in the accompanying Consolidated Statements of Operations for the year ended as follows: upon the discontinuance of hedge accounting approximately $120 million of pre-tax losses were recognized as a component of Impairments and Other Charges while approximately $130 million of losses recognized subsequent to the discontinuance of hedge accounting prior to the deconsolidation of DCP Midstream were recognized as a component of Non-Regulated Electric, Natural Gas, Natural Gas Liquids, and Other Revenues and $64 million of losses recognized subsequent to discontinuance of hedge accounting after the deconsolidation of DCP Midstream were recognized as a component of Other Income and Expenses. Cash settlements on these contracts since the deconsolidation of DCP Midstream on July 1, 2005 of approximately $163 million and $133 million are classified as a component of net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows for the years ended December 31, 2006 and December 31, 2005, respectively.
Commodity Cash Flow Hedges. Some Spectra Energy Capital subsidiaries are exposed to market fluctuations in the prices of natural gas and NGLs related to their natural gas gathering, distribution, processing and marketing activities. Spectra Energy 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 fuel expenses. Spectra Energy Capital uses commodity instruments, such as swaps, futures, forwards and options, as cash flow hedges for natural gas and natural gas liquid transactions. Spectra Energy Capital is only hedging exposures to the price variability with respect to fuel purchases by Union Gas as of December 31, 2006.
The ineffective portion of commodity cash flow hedges from continuing operations resulted in a pre-tax gain of $4 million in 2006, a pre-tax loss of $7 million in 2005 and a pre-tax loss of $2 million in 2004, and is reported primarily in Non-Regulated Electric, Natural Gas, Natural Gas Liquids, and Other in the Consolidated Statements of Operations. Except for the Field Services hedges discussed above, there was no recognition for transactions within continuing operations that no longer qualified as cash flow hedges in 2006, 2005, and 2004.
As of December 31, 2006, $2 million of pre-tax deferred net loss on derivative instruments related to commodity cash flow hedges were accumulated on the Consolidated Balance Sheets in a separate component of
102
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Member’s equity, in AOCI, and are expected to be recognized in earnings during the next twelve 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.
Interest Rate (Fair Value or Cash Flow) Hedges. Changes in interest rates expose Spectra Energy Capital to risk as a result of its issuance of variable and fixed rate debt and commercial paper. Spectra Energy 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. Spectra Energy Capital also enters into financial derivative instruments, including, but not limited to, interest rate swaps and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. Spectra Energy Capital’s fair value and cash flow interest rate hedge ineffectiveness were not material to its consolidated results of operations in 2006, 2005, and 2004.
Foreign Currency (Fair Value, Net Investment or Cash Flow) Hedges. Spectra Energy 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 naturally hedged through debt denominated or issued in the foreign currency. Spectra Energy Capital may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. There was no recognition, a net gain of $1 million and a net loss of $43 million included in the cumulative translation adjustment for hedges of net investments in foreign operations, during 2006, 2005, and 2004, respectively. To monitor its currency exchange rate risks, Spectra Energy Capital uses sensitivity analysis, which measures the impact of devaluation of foreign currencies.
During the first quarter of 2005, Spectra Energy Capital settled certain hedges which were documented and designated as net investment hedges of the investment in Westcoast Energy, Inc. (Westcoast) on their scheduled maturity and paid approximately $162 million. These settlements are classified as a component of net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows. Losses recognized on this net investment hedge have been classified in AOCI as a component of foreign currency adjustments and will not be recognized in earnings unless the complete or substantially complete liquidation of Spectra Energy Capital’s investment in Westcoast occurs.
Other Derivative Contracts. Undesignated. Spectra Energy Capital has used derivative contracts to manage the market risk exposures that arise from marketing and commercial optimization of energy assets and investments, and to manage interest rate and foreign currency exposures. The contracts in this category as of December 31, 2006 are primarily certain contracts held by Spectra Energy Capital related to commodity price risk and interest rate risk. Spectra Energy Capital’s exposure to price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms.
Credit Risk. Spectra Energy Capital’s principal customers for natural gas transportation, storage and gathering and processing services are industrial end-users, marketers, local distribution companies and utilities located throughout the U.S. and Canada. Spectra Energy Capital has concentrations of receivables from natural gas utilities and their affiliates, as well as industrial customers and marketers throughout these regions. These concentrations of customers may affect Spectra Energy Capital’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, Spectra Energy 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. Spectra Energy Capital also obtains cash or letters of credit from customers to provide credit support, where appropriate, based on its financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.
Included in Other Current Assets in the Consolidated Balance Sheets as of December 31, 2006 and December 31, 2005 are collateral assets of a negligible amount and $1,279 million, respectively, which represents cash collateral posted by Spectra Energy Capital with other third parties. Included in Other Current
103
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Liabilities and Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets as of December 31, 2006 and December 31, 2005 are collateral liabilities of approximately $70 million and $608 million, respectively, which represents cash collateral posted by other third parties to Spectra Energy Capital. This decrease in cash collateral posted by Spectra Energy Capital and by others to Spectra Energy Capital is primarily due to the sale and wind-down of trading operations.
Financial Instruments. The fair value of financial instruments, excluding derivatives included elsewhere in this Note and in Note 14, is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2006 and 2005, are not necessarily indicative of the amounts Spectra Energy Capital could have realized in current markets.
Financial Instruments
| As of December 31, | ||||||||||||
| 2006 | 2005 | |||||||||||
Book Value | Approximate Fair Value | Book Value | Approximate Fair Value | |||||||||
| (in millions) | ||||||||||||
Long-term debt(a) | $ | 8,276 | $ | 9,182 | $ | 10,184 | $ | 11,072 | ||||
Long-term SFAS 115 securities | — | — | 231 | 231 | ||||||||
| (a) | Includes current maturities. |
The fair value of cash and cash equivalents, short-term investments, accounts and notes receivable, accounts payable, notes 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
At December 31, 2006, there are no outstanding short-term investments or long-term investments as a result of Spectra Energy Capital’s transfer of Bison to Duke Energy in April 2006 and the transfer of certain businesses to Duke Energy in December 2006.
Short-term investments. At December 31, 2005, Spectra Energy Capital had $521 million 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 the year ended December 31, 2006, Spectra Energy Capital purchased approximately $9,132 million and received proceeds on sale of approximately $9,653 million of short-term investments. During 2005, Spectra Energy Capital purchased approximately $30,115 million and received proceeds on sale of approximately $29,892 million of short-term investments. During 2004, Spectra Energy Capital purchased approximately $54,295 million and received proceeds on sale of approximately $53,768 million of short-term investments. The weighted-average maturity of these debt securities is less than one year.
During 2006, Spectra Energy Capital’s Natural Gas Transmission business unit received shares of stock as consideration for settlement of a customer’s transportation contract. The market value of the equity securities, determined by quoted market prices on the date of receipt, of approximately $28 million is reflected in Gains (Losses) on Sales of Other Assets and Other, net in the Consolidated Statements of Operations for the year ended December 31, 2006. Subsequent to receipt, these securities were accounted for under SFAS No. 115 as trading securities. During the year ended December 31, 2006, these securities were sold and an additional gain of approximately $1 million was recognized in Other income and expenses, net in the Consolidated Statements of Operations for the year ended December 31, 2006.
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Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Other Long-term investments. As discussed in Note 1, on April 1, 2006, Spectra Energy Capital transferred the operations of Bison to Duke Energy. Prior to the transfer of Bison, Spectra Energy Capital invested in debt and equity securities that were held in the captive insurance investment portfolio that were classified as available-for-sale under SFAS No. 115 and, therefore, were carried at estimated fair value based on quoted market prices. These investments were classified as long-term as management did not intend to use them in current operations. The cost of securities sold was determined using the specific identification method. During the period January 1, 2006 through March 31, 2006, Spectra Energy Capital purchased approximately $158 million and received proceeds on sales of approximately $122 million on other long-term investments within the captive insurance portfolio. During 2005, Spectra Energy Capital purchased approximately $803 million and received proceeds on sales of approximately $814 million on other long-term investments within the captive insurance portfolio. During 2004, Spectra Energy Capital purchased approximately $715 million and received proceeds on sales of approximately $769 million on other long-term investments within the captive insurance portfolio.
The estimated fair values of short-term and long-term investments classified as available-for-sale are as follows (in millions):
| As of December 31, | |||||||||
| 2005 | |||||||||
Gross Unrealized Gains | Gross Unrealized Holding | Estimated Fair Value | |||||||
Short-term Investments | $ | — | $ | — | $ | 521 | |||
Total short-term investments | $ | — | $ | — | $ | 521 | |||
Equity Securities | $ | 31 | $ | — | $ | 54 | |||
Corporate Debt Securities | — | 1 | 51 | ||||||
U.S. Government Bonds | — | — | 17 | ||||||
Other | — | 1 | 109 | ||||||
Total long-term investments | $ | 31 | $ | 2 | $ | 231 | |||
For the years ended December 31, 2006, 2005, and 2004 gains of approximately $0, $3 million and $3 million, respectively, were reclassified out of AOCI into earnings.
9. Goodwill
Spectra Energy Capital evaluates goodwill for impairment 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 2006, 2005 or 2004 directly related to these tests. The following table shows the components of goodwill at December 31, 2006:
Changes in the Carrying Amount of Goodwill
Balance December 31, 2005 | Other(d) | Transfer to Duke Energy(e) | Balance at December 31, 2006 | |||||||||||
Natural Gas Transmission(c) | $ | 3,512 | $ | (5 | ) | $ | — | $ | 3,507 | |||||
International Energy | 256 | 11 | (267 | ) | — | |||||||||
Crescent(a) | 7 | (7 | ) | — | — | |||||||||
Total consolidated | $ | 3,775 | $ | (1 | ) | $ | (267 | ) | $ | 3,507 | ||||
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Balance December 31, 2004 | Other(b)(d) | Balance at December 31, 2005 | ||||||||
Natural Gas Transmission | $ | 3,416 | $ | 96 | $ | 3,512 | ||||
Field Services | 480 | (480 | ) | — | ||||||
International Energy | 245 | 11 | 256 | |||||||
Crescent | 7 | — | 7 | |||||||
Total consolidated | $ | 4,148 | $ | (373 | ) | $ | 3,775 | |||
| (a) | Reduction in goodwill at December 31, 2006 reflects the deconsolidation of Crescent in September 2006 (see Note 12). |
| (b) | As a result of the deconsolidation of DCP Midstream in July 2005 goodwill decreased by a net amount of $462 million, which includes the effects of an $18 million transfer of goodwill between Field Services and Natural Gas Transmission as a result of the transfer of Canadian assets in connection with the DCP Midstream disposition transaction (see Note 2). |
| (c) | During 2006, Spectra Energy Capital recorded a $16 million decrease in goodwill as a result of a purchase price adjustment related to a true-up of deferred tax assets related to a prior period acquisition. |
| (d) | Except as noted in (a), (b) and (c), other amounts consist primarily of foreign currency translation. |
| (e) | Represents Spectra Energy Capital’s December 2006 transfer of the operations of International Energy to Duke Energy (see Note 1). |
10. Investments in Unconsolidated Affiliates and Related Party Transactions
Investments in domestic and international affiliates for which Spectra Energy Capital is not the primary beneficiary, but over which it has significant influence, are accounted for using the equity method. Spectra Energy Capital received distributions of $859 million in 2006 from those investments. Of these distributions, $707 million are included in Other, assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows and $152 million are included in Distributions from Equity Investments within Cash Flows from Investing Activities on the accompanying Consolidated Statements of Cash Flows. Spectra Energy Capital received distributions of $856 million in 2005. Of these distributions, $473 million are included in Other, assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows and $383 million are included in Distributions from Equity Investments within Cash Flows from Investing Activities on the accompanying Consolidated Statements of Cash Flows. Spectra Energy Capital received distributions of $139 million in 2004, which are included in Other, assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows. Spectra Energy 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 2006 dispositions.)
As of December 31, 2006 and 2005, the carrying amount of investments in affiliates approximated the amount of underlying equity in net assets.
Natural Gas Transmission. As of December 31, 2006, investments primarily included a 50% interest in Gulfstream. Gulfstream is an interstate natural gas pipeline that extends from Mississippi and Alabama across the Gulf of Mexico to Florida. Although Spectra Energy Capital owns a significant portion of Gulfstream, it is not consolidated as Spectra Energy Capital does not hold a majority of voting control or have the ability to exercise control over Gulfstream.
Field Services. In July 2005, Spectra Energy Capital completed the transfer of a 19.7% interest in DCP Midstream to ConocoPhillips, Spectra Energy Capital’s co-equity owner in DCP Midstream, which reduced Spectra Energy Capital’s ownership interest in DCP Midstream from 69.7% to 50% (the DCP Midstream disposition transactions) and resulted in Spectra Energy Capital and ConocoPhillips becoming equal 50% owners in DCP Midstream. As a result of the DCP Midstream disposition transaction, Spectra Energy Capital deconsolidated its investment in DCP Midstream which has subsequently been accounted for as an investment
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
utilizing the equity method of accounting (see Note 2). Additionally, in February 2005, DCP Midstream sold its wholly owned subsidiary TEPPCO GP, which is the general partner of TEPPCO LP, for approximately $1.1 billion and Spectra Energy Capital sold its limited partner interest in TEPPCO LP for approximately $100 million, in each case to Enterprise GP Holdings LP, an unrelated third party. These transactions resulted in pre-tax gains of approximately $1.8 billion. For the three months ended March 31, 2005, TEPPCO LP had operating revenues of approximately $1,524 million, operating expenses of approximately $1,463 million, operating income of approximately $61.2 million, income from continuing operations of approximately $46.3 million, and net income of approximately $47.4 million.
Investments in Unconsolidated Affiliates
| As of: | ||||||||||||||||||
| December 31, 2006 | December 31, 2005 | |||||||||||||||||
| Domestic | International | Total | Domestic | International | Total | |||||||||||||
| (in millions) | ||||||||||||||||||
Natural Gas Transmission | $ | 434 | $ | 18 | $ | 452 | $ | 428 | $ | 20 | $ | 448 | ||||||
Field Services(a) | 1,166 | — | 1,166 | 1,290 | — | 1,290 | ||||||||||||
International Energy(b) | — | — | — | — | 155 | 155 | ||||||||||||
Crescent(b) | — | — | — | 17 | — | 17 | ||||||||||||
Other(b) | — | — | — | 14 | 7 | 21 | ||||||||||||
Total | $ | 1,600 | $ | 18 | $ | 1,618 | $ | 1,749 | $ | 182 | $ | 1,931 | ||||||
| (a) | Includes Spectra Energy Capital’s 50% interest in DCP Midstream subsequent to deconsolidation of DCP Midstream on July 1, 2005. |
| (b) | As discussed in Note 1, operations were transferred from Spectra Energy Capital to Duke Energy in December 2006. |
Equity in Earnings of Unconsolidated Affiliates(a)
| For the Years Ended: | |||||||||||||||||||||||||||
| December 31, 2006 | December 31, 2005 | December 31, 2004 | |||||||||||||||||||||||||
| Domestic | International | Total | Domestic | International | Total | Domestic | International | Total | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||
Natural Gas Transmission | $ | 33 | $ | 2 | $ | 35 | $ | 42 | $ | 5 | $ | 47 | $ | 26 | $ | 4 | $ | 30 | |||||||||
Field Services(b) | 574 | — | 574 | 308 | — | 308 | 60 | — | 60 | ||||||||||||||||||
Total | $ | 607 | $ | 2 | $ | 609 | $ | 350 | $ | 5 | $ | 355 | $ | 86 | $ | 4 | $ | 90 | |||||||||
| (a) | Excludes amounts in discontinued operations, which primarily represent equity earnings of investments within the following: International Energy, Crescent and the equity investments within Other, which were transferred by Spectra Energy Capital to Duke Energy in December 2006. |
| (b) | Includes Spectra Energy Capital’s 50% equity in earnings of DCP Midstream subsequent to deconsolidation on July 1, 2005. |
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Summarized Combined Financial Information of Unconsolidated Affiliates
| As of December 31, | ||||||||
| 2006 | 2005 | |||||||
| (in millions) | ||||||||
Balance Sheet(a) | ||||||||
Current assets | $ | 2,217 | $ | 3,395 | ||||
Non-current assets | 6,492 | 7,744 | ||||||
Current liabilities | (2,226 | ) | (3,392 | ) | ||||
Non-current liabilities | (3,323 | ) | (3,237 | ) | ||||
Net assets | $ | 3,160 | $ | 4,510 | ||||
| For the Years Ended December 31, | |||||||||
| 2006 | 2005 | 2004 | |||||||
| (in millions) | |||||||||
Income Statement(a)(b) | |||||||||
Operating revenues | $ | 13,586 | $ | 8,799 | $ | 7,326 | |||
Operating expenses | 11,855 | 7,650 | 6,872 | ||||||
Net income | 1,565 | 1,076 | 415 | ||||||
| (a) | Amounts include DCP Midstream for the respective periods subsequent to deconsolidation. |
| (b) | Includes amounts of unconsolidated affiliates of the International Energy and Crescent segments which were transferred to Duke Energy in December 2006 (see Note 12) and presented as discontinued operations for the years ended December 31, 2006, 2005 and 2004 in the accompanying Consolidated Statements of Operations. |
Related Party Transactions.
During the year ended December 31, 2006, Spectra Energy Capital advanced approximately $89 million to its parent, Duke Energy, and forgave advances to Duke Energy of approximately $602 million. The advance is presented as Advances (to) from Parent within financing activities in the Consolidated Statements of Cash Flows for the year ended December 31, 2006. The advances forgiven have been presented as a non-cash financing activity for the year ended December 31, 2006.
During the year ended December 31, 2006, Spectra Energy Capital distributed approximately $2,361 million to Duke Energy to provide funding support for Duke Energy’s dividend payments and share repurchase plan. The distribution was principally obtained from the proceeds received on Spectra Energy Capital’s sale of 50% of Crescent to the MS Members (see Note 12). During the year ended December 31, 2005, Spectra Energy Capital distributed approximately $2,100 million to Duke Energy to provide funding for the execution of Duke Energy’s accelerated share acquisition plan. The distribution was principally obtained from Spectra Energy Capital’s portion of the cash proceeds realized from the sale by DCP Midstream of TEPPCO GP and Spectra Energy Capital’s sale of its limited partner interest in TEPPCO, noted above.
See Notes 1 and 12 for discussion of direct and indirect transfers of certain business from Spectra Energy Capital to Duke Energy and Duke Energy Ohio during 2006.
During 2004, $267 million of cash advances were received by Spectra Energy Capital from Duke Energy as a partial return of the income tax benefit associated with the transfer of deferred tax assets to Duke Energy in 2004. During the first quarter of 2005, Duke Energy forgave these advances of $267 million and Spectra Energy Capital classified the $267 million as an addition to Member’s Equity. Additionally, during the third quarter of 2005, Duke Energy forgave additional advances of $494 million and Spectra Energy Capital classified the $494 million as an addition to Member’s Equity. These transactions have been presented as a non-cash financing activity in the Consolidated Statements of Cash Flows for the year ended December 31, 2005.
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
During the year ended December 31, 2005, Spectra Energy Capital received capital contributions of $269 million from Duke Energy, which Spectra Energy Capital classified as an addition to Member’s Equity. Additionally, during the year ended December 31, 2005, Spectra Energy Capital advanced $242 million to Duke Energy. These transactions are presented as a component of net cash used in financing activities for the year ended December 31, 2005.
During the year ended December 31, 2004, Spectra Energy Capital received $107 million in advances from Duke Energy. This transaction is presented as a component of net cash used in financing activities for the year ended December 31, 2004.
Certain balances due to or due from Duke Energy or other affiliates included in the Consolidated Balance Sheets as of December 31, 2006 and December 31, 2005 are as follows. See additional transactions and balances described below.
Assets/(Liabilities) | December 31, 2006 | December 31, 2005 | |||||
| (in millions) | |||||||
Advances receivable/(payable)(b) | $ | 2 | $ | (30 | ) | ||
Accounts receivable | 15 | — | |||||
Taxes receivable(a) | — | 187 | |||||
Other noncurrent assets(d) | 27 | — | |||||
Other current liabilities(c) | 18 | (2 | ) | ||||
| (a) | Taxes receivable are classified as Other Current Assets in the Consolidated Balance Sheets. |
| (b) | Advances receivable are included in Other within Investments and Other Assets on the Consolidated Balance Sheets. Advances payable are included in Other within Deferred Credits and Other Liabilities 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 balance is classified as Other Current Liabilities on the Consolidated Balance Sheets. |
| (d) | The balance is classified in Other within Investments and Other Assets on the Consolidated Balance Sheets. |
For the years ended December 31, 2006, 2005 and 2004, Spectra Energy Capital recorded income in the amount of approximately $82 million, $68 million, and $155 million, respectively, related to management fees charged to an unconsolidated affiliate of Spectra Energy Capital. These amounts are recorded in Other Income and Expenses, net on the Consolidated Statements of Operations. Additionally, for the years ended December 31, 2006, 2005 and 2004, Spectra Energy Capital recognized recoveries of expenses in the amount of $777 million, $466 million and $416 million, respectively. These amounts represent recoveries of direct and allocated corporate governance and shared service costs charged to unconsolidated affiliates and are reflected as an offset within Operation, Maintenance, and Other and Depreciation and Amortization within Operating Expenses on the Consolidated Statements of Operations. Also included in Operations, Maintenance and Other within Operating Expenses in the Consolidated Statements of Operations for the year ended December 31, 2006 is approximately $23 million of allocated costs charged to Spectra Energy Capital by an affiliate of Cinergy, which excludes approximately $6 million which is included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.
Additionally, included in Operations, Maintenance and Other within Operating Expenses in the Consolidated Statements of Operations for the year ended December 31, 2006 is approximately $22 million related primarily to insurance premiums paid to Bison subsequent to the transfer of Bison to Duke Energy in April 2006.
Outstanding notes receivable from unconsolidated affiliates were $50 million as of December 31, 2005, which represents International Energy’s $50 million note receivable from the Campeche project, a 50% owned joint venture. Amounts are included in Notes Receivable on the Consolidated Balance Sheets. The outstanding note receivable had interest rates approximating current market rates.
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
International Energy loaned money to Campeche to assist in the costs to build. International Energy received principal and interest payments of approximately $11 million, $5 million and $7 million from Campeche, a 50% owned DEI affiliate, during 2006, 2005 and 2004, respectively.
Natural Gas Transmission has a 50% ownership in two pipeline companies, Gulfstream, an operating pipeline, and Islander East, LLC, a development stage pipeline as well as a 50% ownership in a power plant, McMahon Cogeneration Plant, a cogeneration natural gas fired facility transferred to Natural Gas Transmission from DENA during 2005. Natural Gas Transmission provides certain administrative and other services to the pipeline companies and the power plant. Natural Gas Transmission recorded recoveries of costs from these affiliates of $19 million, $12 million, and $8 million during 2006, 2005, and 2004, respectively. The outstanding receivable from these affiliates was $5 million and $2 million as of December 31, 2006 and 2005, respectively.
In October 2005, Gulfstream issued $500 million aggregate principal amount of 5.56% Senior Notes due 2015 and $350 million aggregate principal amount of 6.19% Senior Notes due 2025. The proceeds were used by Gulfstream to pay off a construction loan and the balance of the proceeds, net of transaction costs, of approximately $620 million was distributed to the partners based upon their ownership percentage (approximately $310 million was received by Natural Gas Transmission and are included in Distributions from Equity Investments within Cash Flows from Investing Activities in the accompanying Consolidated Statements of Cash Flows).
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 GP, which was sold in February 2005). Total revenues from these affiliates were approximately $98 million for the six months ended June 30, 2005, and $278 million for the year ended December 31, 2004. Total purchases from these affiliates were approximately $77 million for the six months ended June 30, 2005, and $125 million for the year ended December 31, 2004. Total operating expenses were approximately $1 million for the six months ended June 30, 2005, and $4 million for the year ended December 31, 2004. Reductions in revenues and purchases in 2005 as compared to 2004 are principally due to the sale of TEPPCO GP and deconsolidation of DCP Midstream, effective July 1, 2005.
In July 2005, DCP Midstream was deconsolidated due to the transfer of a 19.7% interest to ConocoPhillips and has been subsequently accounted for as an equity investment (see Note 2). Spectra Energy Capital’s 50% of equity in earnings of DCP Midstream for the year ended December 31, 2006 and the period July 1, 2005 through December 31, 2005 was $574 million and $292 million, respectively, and Spectra Energy Capital’s investment in DCP Midstream as of December 31, 2006 was $1,166 million, which is included in Investments in Unconsolidated Affiliates in the accompanying Consolidated Balance Sheets. For the year ended December 31, 2006, Spectra Energy Capital had gas sales to, purchases from, and other operating revenues from affiliates of DCP Midstream of approximately $137 million, $41 million and $12 million, respectively. As of December 31, 2006, Spectra Energy Capital had trade receivables from and trade payables to DCP Midstream amounting to approximately $71 million and $56 million, respectively. Between July 1, 2005 and December 31, 2005, Spectra Energy Capital had gas sales to, purchases from, and other operating revenues from affiliates of DCP Midstream of approximately $67 million, $65 million and $12 million, respectively. As of December 31, 2005, Spectra Energy Capital had trade receivables from and trade payables to DCP Midstream of approximately $18 million and $47 million, respectively. Additionally, Spectra Energy Capital received approximately $725 million and $360 million for its share of distributions paid by DCP Midstream in 2006 and 2005, respectively. Spectra Energy Capital has recognized an approximate $64 million receivable as of December 31, 2006 due to its share of quarterly tax distributions declared by DCP Midstream in 2006 and paid in 2007, as compared to $90 million in 2005, which was paid in 2006. Of these distributions $573 million and $287 million were included in Other, assets within Cash Flows from Operating Activities for the years ended 2006 and 2005, respectively, and approximately $152 million and $73 million were included in Distributions from Equity Investments within Cash Flows from Investing Activities for the years ended 2006 and 2005, respectively, within the accompanying
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Consolidated Statements of Cash Flows. Summary financial information for DCP Midstream, which has been accounted for under the equity method since July 1, 2005 is as follows:
Twelve-months Ended December 31, 2006 | Six-months Ended December 31, 2005 | |||||
| (in millions) | ||||||
Operating revenues | $ | 12,335 | $ | 7,463 | ||
Operating expenses | 11,063 | 6,814 | ||||
Operating income | 1,272 | 649 | ||||
Net income | 1,135 | 584 | ||||
| December 31, 2006 | December 31, 2005 | |||||
| (in millions) | ||||||
Current assets | $ | 2,129 | $ | 2,706 | ||
Non-current assets | 4,767 | 5,005 | ||||
Current liabilities | 2,177 | 3,068 | ||||
Non-current liabilities | 2,391 | 2,038 | ||||
Minority interest | 71 | 95 | ||||
As of December 31, 2006, there was an immaterial basis difference between Spectra Energy Capital’s carrying value of the investment in DCP Midstream and the value of Spectra Energy Capital’s proportionate share of the underlying net assets in DCP Midstream.
DCP Midstream is a limited liability company which is a pass-through entity for U.S. income tax purposes. DCP Midstream also owns corporations who file their own respective, federal, foreign and state income tax returns and income tax expense related to these corporations is included in the income tax expense of DCP Midstream. Therefore, DCP Midstream’s net income does not include income taxes for earnings which are pass-through to the members based upon their ownership percentage and Spectra Energy Capital recognizes the tax impacts of its share of DCP Midstream’s pass-through earnings in its income tax expense from continuing operations in the accompanying Consolidated Statements of Operations.
In 2005, DCP Midstream formed DCP Midstream Partners, LP (a master limited partnership). DCP Midstream Partners, LP (DCPLP) completed an initial public offering (IPO) transaction in December 2005 that resulted in net proceeds of approximately $210 million. As a result, DCP Midstream has a 42% ownership interest in DCPLP, consisting of a 40% limited partner ownership interest and a 2% general partner ownership interest. DCP Midstream’s ownership interest in the general partner of DCPLP is 100%. The gain on the IPO transaction has been deferred by DCP Midstream until DCP Midstream converts its subordinated units in DCP to common units, which will occur no earlier than December 31, 2008.
111
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
An indirect wholly owned subsidiary of Spectra Energy Capital contributed all the membership interest in Crescent to a newly-formed joint venture causing Spectra Energy Capital to deconsolidate Crescent as of September 7, 2006 (see Note 12). Spectra Energy Capital’s 50% of equity in earnings of Crescent for the period from September 8, 2006 through December 31, 2006 was $15 million. As discussed in Note 1, in December 2006 Spectra Energy Capital transferred its investment in Crescent to Duke Energy. As a result of this transfer, the results of operations, as well as the equity earnings for the period subsequent to September 7, 2006, are included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations. Summary financial information for Crescent, which has been accounted for under the equity method since September 7, 2006 is as follows:
September 7 December 31, | |||
| (in millions) | |||
Operating revenues | $ | 179 | |
Operating expenses | 152 | ||
Operating income | 27 | ||
Net income | 30 | ||
Also see Notes 2, 11, 14, and 17 for additional related party information.
11. Impairments, Severance, and Other Charges
Field Services. During the year ended December 31, 2005, Field Services recorded a charge of approximately $120 million due to the reclassification into earnings of pre-tax unrealized losses from AOCI as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk. See Note 7 for a discussion of the impacts of the DCP Midstream disposition transaction on certain cash flow hedges.
In the third quarter of 2004, Field Services recorded impairments of approximately $22 million related to DCP Midstream operating assets. Additionally, in the third quarter of 2004, Field Services recorded an impairment of approximately $23 million related to equity method investments at DCP Midstream. The impairment is included in (Losses) Gains on Sales and Impairments of Equity Method 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.
Severance. During 2002, Duke Energy 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 applied to individuals notified of layoffs between that date and January 1, 2006.
Severance Reserve | Balance at January 1, 2006 | Provision/ Adjustments | Noncash Adjustments(d) | Cash Reductions | Balance at December 31, 2006 | ||||||||||||
| (in millions) | |||||||||||||||||
Natural Gas Transmission | $ | 3 | $ | — | $ | — | $ | (1 | ) | $ | 2 | ||||||
Other(c) | 28 | 15 | (24 | ) | (19 | ) | — | ||||||||||
Total(a) | $ | 31 | $ | 15 | $ | (24 | ) | $ | (20 | ) | $ | 2 | |||||
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Balance at January 1, 2005 | Provision/ Adjustments | Noncash Adjustments | Cash Reductions | Balance at December 31, 2005 | |||||||||||||
Natural Gas Transmission | $ | 6 | $ | 1 | $ | (1 | ) | $ | (3 | ) | $ | 3 | |||||
Field Services(b) | — | 1 | (1 | ) | — | — | |||||||||||
International Energy | 1 | — | (1 | ) | — | — | |||||||||||
Other(c) | 4 | 26 | — | (2 | ) | 28 | |||||||||||
Total(a) | $ | 11 | $ | 28 | $ | (3 | ) | $ | (5 | ) | $ | 31 | |||||
Balance at January 1, 2004 | Provision/ Adjustments | Noncash Adjustments | Cash Reductions | Balance at December 31, 2004 | |||||||||||||
Natural Gas Transmission | $ | 29 | $ | 1 | $ | (6 | ) | $ | (18 | ) | $ | 6 | |||||
Field Services(b) | 6 | 1 | — | (7 | ) | — | |||||||||||
International Energy | 6 | — | (4 | ) | (1 | ) | 1 | ||||||||||
Other(c) | 49 | 3 | (5 | ) | (43 | ) | 4 | ||||||||||
Total(a) | $ | 90 | $ | 5 | $ | (15 | ) | $ | (69 | ) | $ | 11 | |||||
| (a) | Substantially all expected severance costs will be applied to the reserves within one year. |
| (b) | Includes minority interest. |
| (c) | Severance expense (benefit) included in Income (Loss) From Discontinued Operations, net of tax in the Consolidated Statements of Operations was $(9) million, $25 million, and $(6) million for 2006, 2005, and 2004, respectively. |
| (d) | Approximately $13 million of noncash adjustments in 2006 relate to the transfer of Spectra Energy Capital businesses to Duke Energy and approximately $11 million relates to noncash adjustments at former DENA due to a change in estimate. |
12. Discontinued Operations and Assets Held for Sale
As discussed in Note 1, in April 2006, Spectra Energy Capital indirectly transferred to Duke Energy Ohio its ownership interest in former DENA’s Midwestern plants. Accordingly, the results of operations for former DENA’s Midwestern assets up through April 1, 2006 have been reflected as discontinued operations within Commercial Power in the accompanying Consolidated Statements of Operations. No gain or loss was recognized on the distribution of these operations to Duke Energy as the transfer was among entities under common control.
Also as discussed in Note 1, in December 2006, Spectra Energy Capital transferred certain operations to Duke Energy. Operations transferred include International Energy, Spectra Energy Capital’s effective 50% interest Crescent and certain operations within Other, primarily DETM, DukeNet, Spectra Energy Capital’s 50% interest in D/FD and DEM. The results of these operations are presented as discontinued operations for the years ended December 31, 2006, 2005 and 2004 in the accompanying Consolidated Statements of Operations. No gain or loss was recognized on the distribution of these operations to Duke Energy as the transfer was among entities under common control. Approximately $5.1 billion of assets, $1.9 billion of liabilities (which includes approximately $0.9 billion of debt), $0.2 billion of minority interest and $3.0 billion of member’s equity were transferred from Spectra Energy Capital to Duke Energy in December 2006. Spectra Energy Capital does not anticipate significant continuing involvement in the transferred businesses.
During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of former DENA remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The former DENA assets to be divested included:
| • | Approximately 6,100 MW of power generation located primarily in the Western and Eastern United States, including all of the commodity contracts (primarily forward gas and power contracts) related to these facilities, |
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
| • | All remaining commodity contracts related to former DENA Southeastern generation operations, which were substantially disposed of in 2004, and certain commodity contracts related to former DENA Midwestern power generation facilities, and |
| • | Contracts related to former DENA energy marketing and management activities, which include gas storage and transportation, structured power and other contracts. |
The results of operations of former DENA Western and Eastern United States generation assets, including related commodity contracts, certain contracts related to former DENA energy marketing and management activities and certain general and administrative costs, have been classified as discontinued operations within Other for the years ended December 31, 2006, 2005 and 2004 in the accompanying Consolidated Statements of Operations.
The following table summarizes the results classified as Income (Loss) from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.
Discontinued Operations
| Operating Revenues | Pre-tax Earnings (Loss) | Income Tax Expense (Benefit) | Income (Loss) From Discontinued Operations, Net of Tax | ||||||||||||
| (in millions) | |||||||||||||||
Year Ended December 31, 2006 | |||||||||||||||
Commercial Power | $ | 15 | $ | (16 | ) | $ | (2 | ) | $ | (14 | ) | ||||
International Energy | 961 | 64 | 54 | 10 | |||||||||||
Crescent | 221 | 518 | 206 | 312 | |||||||||||
Other(a) | 788 | (197 | ) | (197 | ) | — | |||||||||
Total consolidated | $ | 1,985 | $ | 369 | $ | 61 | $ | 308 | |||||||
Year Ended December 31, 2005 | |||||||||||||||
Field Services | $ | 4 | $ | — | $ | — | $ | — | |||||||
Commercial Power | 113 | (78 | ) | 16 | (94 | ) | |||||||||
International Energy | 745 | 275 | 110 | 165 | |||||||||||
Crescent | 497 | 304 | 100 | 204 | |||||||||||
Other(a) | 2,813 | (1,128 | ) | (122 | ) | (938 | ) | ||||||||
Total consolidated | $ | 4,172 | $ | (627 | ) | $ | 104 | $ | (1,006 | ) | |||||
Year Ended December 31, 2004 | |||||||||||||||
Field Services | $ | 79 | $ | (14 | ) | $ | (5 | ) | $ | (9 | ) | ||||
Commercial Power | 53 | (104 | ) | (8 | ) | (96 | ) | ||||||||
International Energy | 704 | 454 | 81 | 373 | |||||||||||
Crescent | 439 | 233 | 78 | 155 | |||||||||||
Other(a) | 3,237 | (31 | ) | (201 | ) | 170 | |||||||||
Total consolidated | $ | 4,512 | $ | 538 | $ | (55 | ) | $ | 593 | ||||||
| (a) | Other includes the results for former DENA’s discontinued operations, excluding the operations of the Midwest and Southeast plants, which were previously reported in the DENA segment. |
There were no assets or liabilities classified as held for sale in the accompanying Consolidated Balance Sheets as of December 31, 2006. The following table presents the carrying values of the major classes of assets and associated liabilities held for sale in the accompanying Consolidated Balance Sheets as of December 31, 2005. All amounts at December 31, 2005 relate to businesses transferred to Duke Energy during December 2006
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
as discussed in Note 1, and primarily relate to former DENA’s assets that were sold to LS Power or Barclays during 2006, as discussed further below. However, the balances below do not include the assets and liabilities of the businesses transferred to Duke Energy in December 2006.
Summarized Balance Sheet Information for Assets and Associated Liabilities Held for Sale
| December 31, 2005 | |||
| (in millions) | |||
Current assets | $ | 1,528 | |
Investments and other assets | 2,059 | ||
Property, plant and equipment, net | 1,538 | ||
Total assets held for sale | $ | 5,125 | |
Current liabilities | $ | 1,488 | |
Long-term debt | 61 | ||
Deferred credits and other liabilities | 2,024 | ||
Total liabilities associated with assets held for sale | $ | 3,573 | |
The following significant transactions of Spectra Energy Capital, the impacts of which are included in Income (Loss) From Discontinued Operations, net of tax on the Consolidated Statements of Income, occurred during the years ended December 31, 2006, 2005 and 2004.
Year Ended December 31, 2006
Acquisitions. During the first quarter of 2006, International Energy closed on two transactions which resulted in the acquisition of an additional 27% interest in the Aguaytia Integrated Energy Project (Aguaytia), located in Peru, for approximately $31 million (approximately $18 million net of cash acquired). The project’s scope includes the production and processing of natural gas, sale of liquefied petroleum gas (LPG) and NGLs and the generation, transmission and sale of electricity from a 177 megawatt power plant. These acquisitions increased International Energy’s ownership in Aguaytia to 66% and resulted in Spectra Energy Capital accounting for Aguaytia as a consolidated entity. Prior to the acquisition of this additional interest, Aguaytia was accounted for as an equity method investment. No goodwill was recorded as a result of this acquisition.
During the first quarter of 2006, Spectra Energy Capital acquired the remaining 33 1/3% interest in Bridgeport Energy LLC (Bridgeport) from United Bridgeport Energy LLC (UBE) for approximately $71 million. No goodwill was recorded as a result of this acquisition. The assets and liabilities of Bridgeport were included as part of former DENA’s power generation assets which were sold to a subsidiary of LS Power Equity Partners (LS Power) (see below).
Dispositions. Significant sales of other assets and equity investments during 2006 are detailed as follows:
| • | Crescent. On September 7, 2006, a wholly owned subsidiary of Spectra Energy Capital closed an agreement to create a joint venture of Crescent (the Crescent JV) with Morgan Stanley Real Estate Fund V U.S., L.P. (MSREF) and other affiliated funds controlled by Morgan Stanley (collectively the “MS Members”). Under the agreement, the Spectra Energy Capital subsidiary contributed all of the membership interests in Crescent to a newly-formed joint venture, which was ascribed an enterprise value of approximately $2.1 billion as of December 31, 2005. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.21 billion, net of transaction costs, of which approximately $1.19 billion was immediately distributed to Spectra Energy Capital. Immediately following the debt transaction, the MS Members collectively acquired a 49% membership interest in the Crescent JV from Spectra Energy Capital for a purchase price of approximately $415 |
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
million. A 2% interest in the Crescent JV was also issued by the joint venture to the President and Chief Executive Officer of Crescent which is subject to forfeiture if the executive voluntarily leaves the employment of the Crescent JV within a three year period. Additionally, this 2% interest can be put back to the Crescent JV after three years or possibly earlier upon the occurrence of certain events at an amount equal to 2% of the fair value of the Crescent JV’s equity as of the put date. Therefore, the Crescent JV will accrue the obligation related to the put as a liability over the three year forfeiture period. In conjunction with the Crescent JV transaction, Spectra Energy Capital recognized a pre-tax gain on the sale of approximately $250 million in 2006. As a result of the Crescent transaction, Spectra Energy Capital no longer controlled the Crescent JV and on September 7, 2006 deconsolidated its investment in Crescent and accounted for its investment in the Crescent JV utilizing the equity method of accounting. The proceeds from the sale were recorded on the Consolidated Statements of Cash Flows as follows: approximately $1.2 billion in long-term debt proceeds, net of issuance costs, were classified as Proceeds from the issuance of long-term debt within Financing Activities, and approximately $380 million, which represents cash received from the MS Members net of cash held by Crescent as of the transaction date, were classified as Net proceeds from the sales of and distributions from equity investments and other assets, and sales of and collections on notes receivable within Investing Activities. |
For the period from January 1, 2006 to September 7, 2006, Crescent commercial and multi-family real estate sales resulted in $254 million of proceeds and $201 million of net pre-tax gains. Sales primarily consisted of two office buildings at Potomac Yard in Washington, D.C. for a pre-tax gain of $81 million and land at Lake Keowee in northwestern South Carolina for a pre-tax gain of $52 million, as well as several other large land tract sales.
| • | Other. As discussed above, during the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Approximately $700 million was incurred from the announcement date through December 31, 2006, of which approximately $230 million was incurred during the year ended December 31, 2006. In January 2006, Spectra Energy Capital signed an agreement to sell to LS Power former DENA’s entire fleet of power generation assets outside the Midwest. In May 2006, the transaction with LS Power closed. Total proceeds from the sale were approximately $1.6 billion. As of December 31, 2006, the exit activities of former DENA were substantially complete. See below for further discussion. In 2006, Spectra Energy Capital recognized an approximate $51 million pre-tax gain on the sale of available-for-sale securities that were included in Assets Held for Sale on the Consolidated Balance Sheets. |
Impairments. International Energy.In 2006, International Energy recorded a $50 million pre-tax other-than-temporary impairment charge related to an investment in Campeche, 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 GCSA expired in November 2006 and a nine month extension was executed in October 2006. In the second quarter of 2006, based on ongoing discussions with PEMEX, it was determined that there was a limited future need for Campeche’s gas compression services. Management of International Energy determined that it was probable that the Campeche investment would ultimately be sold or the GCSA would be renewed for a significantly lower rate. An other-than-temporary impairment loss was recorded to reduce the carrying value to management’s best estimate of realizable value. The charges consisted of a $17 million impairment of the carrying value of the equity method investment and a $33 million reserve against notes receivable from Campeche.
In December 2006, Spectra Energy Capital engaged in discussions with a potential buyer of International Energy’s assets in Bolivia. Such discussions to sell the assets were subject to a binding agreement between the parties, which was finalized in February 2007 (subsequent to the December 2006 transfer of International Energy to Duke Energy), and resulted in the sale of International Energy’s 50% ownership interest in two hydroelectric power plants near Cochabamba, Bolivia to Econergy International for approximately $20 million. Based upon the
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
agreed upon selling price of the assets, in December 2006 Spectra Energy Capital recorded pre-tax impairment charges of approximately $28 million. The impairment charges reduced the carrying value of the assets to the estimated selling price pursuant to the aforementioned agreement.
Year Ended December 31, 2005
Dispositions. Significant sales of other assets and equity investments during 2005 are detailed as follows:
| • | Crescent. For the year ended December 31, 2005, Crescent’s commercial and multi-family real estate sales resulted in $372 million of proceeds and $197 million of net pre-tax gains. Sales included a large land sale in Lancaster County, South Carolina that resulted in $42 million of pre-tax gains, and several other “legacy” land sales. Additionally, Crescent had $45 million in pre-tax income related to a distribution from an interest in a portfolio of commercial office buildings. |
| • | Other. In connection with the exit plan of former DENA described above, Spectra Energy Capital recognized pre-tax losses of approximately $1.1 billion in 2005, principally related to: |
| • | The discontinuation of the normal purchase/normal sale exception for certain forward power and gas contracts (an approximate $1.9 billion pre-tax charge) |
| • | The reclassification of approximately $1.2 billion of pre-tax deferred net gains in AOCI for cash flow hedges of forecasted gas purchase and power sale transactions that will no longer occur as a result of the exit plan |
| • | Pre-tax impairments of approximately $0.2 billion to reduce the carrying value of the plants that are expected to be sold to their estimated fair value less cost to sell. Fair value of the assets that are expected to be sold was estimated based upon the signed agreement with LS Power, as discussed below |
| • | Pre-tax losses of approximately $0.4 billion as the result of selling certain gas transportation and structured contracts (as discussed further below), and |
| • | Pre-tax deferred gains in AOCI of approximately $0.2 billion related to the discontinued cash flow hedges of forecasted gas purchase and power sale transactions, which were recognized as the forecasted transactions occurred. |
As of the September 2005 exit announcement date, management anticipated that additional charges would be incurred related to the exit plan, including termination costs for gas transportation, storage, structured power and other contracts of approximately $600 million to $800 million, which included approximately $40 million to $60 million of severance, retention and other transaction costs. Included in these amounts are the effects of former DENA’s November 2005 agreement to sell substantially all of its commodity contracts related to the Southeastern generation operations, which were substantially disposed of in 2004, certain commodity contracts related to former DENA Midwestern power generation facilities, and contracts related to former DENA energy marketing and management activities. Excluded from the contracts sold to Barclays are commodity contracts associated with the near-term value of former DENA West and Northeastern generation assets and with remaining gas transportation and structured power contracts. Approximately $470 million was incurred from the announcement date through December 31, 2005.
Among other things, the agreement provides that all economic benefits and burdens under the contracts were transferred to Barclays. Cash consideration paid to Barclays amounted to approximately $100 million in 2005 and approximately $600 million in January 2006. Additionally, in January 2006 Barclays provided Spectra Energy Capital with cash equal to the net cash collateral posted by former DENA under the contracts of approximately $540 million. The novation or assignment of physical power contracts was subject to FERC approval, which was received in January 2006.
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
In the first quarter of 2005, Spectra Energy Capital’s Grays Harbor facility was sold to an affiliate of Invenergy LLC, resulting in a pre-tax gain of approximately $21 million (excludes any potential contingent consideration).
In the third quarter of 2005, Spectra Energy Capital completed the sale of Bayside Power L.P. (Bayside) to affiliates of Irving Oil Limited (Irving), under which Irving would purchase Spectra Energy Capital’s 75% interest in Bayside.
Impairments. International Energy.A $20 million other than temporary impairment in value of the Campeche investment was recognized during the third quarter of 2005 to write down the investment to its estimated fair value.
Crescent. In the third quarter of 2005, Crescent recognized pre-tax impairment charges of approximately $16 million related to a residential community near Hilton Head Island, South Carolina, that includes both residential lots and a golf club, to reduce the carrying value of the community to its estimated fair value. This community had incurred higher than expected costs and had been impacted by lower than anticipated sales volume. The fair value of the remaining community assets was determined based upon management’s estimate of discounted future cash flows generated from the development and sale of the community.
Year Ended December 31, 2004
Dispositions. Significant sales of other assets in 2004 are detailed as follows:
| • | Field Services. 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, which approximated these assets’ carrying value. Also, 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. |
| • | Commercial Power. During 2004, a 25% undivided interest in Commercial Power’s Vermillion facility was sold for proceeds of approximately $44 million. This sale was anticipated in 2003 and, therefore, an $18 million pre-tax loss on sale was recorded during 2003. |
| • | 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. A $13 million non-cash charge related to a note receivable from Cantarell, was recorded in the first quarter of 2004. |
| • | Crescent. For the year ended December 31, 2004, Crescent’s commercial and multi-family real estate sales resulted in $606 million of proceeds, and $197 million of net gains. 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. |
| • | Other. For the year ended December 31, 2004, Spectra Energy Capital’s discontinued operations included sales and impairments of merchant power plants located in Washington (“Grays Harbor” plant), Nevada (“Moapa” plant) and New Mexico (“Luna” plant) (collectively, the deferred plants). Details are as follows: |
| • | The partially completed Moapa facility was sold to Nevada Power Company and resulted in $186 million in net proceeds and a pre-tax gain of approximately $140 million. |
| • | The partially completed Luna facility was sold 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. |
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
| • | In December 2004, Spectra Energy Capital agreed to sell the partially completed Grays Harbor facility to an affiliate of Invenergy LLC and terminated its capital lease associated with the dedicated pipeline which would have transported natural gas to the plant. This termination resulted in a $20 million pre-tax charge. As discussed above, in the first quarter of 2005, Grays Harbor was sold. |
Additional assets and business sold in 2004 totaled $270 million in net proceeds. Those sales resulted in net pre-tax losses of $55 million. These sales primarily related to some contracts at DETM. DETM held a net liability position in certain contracts and, as part of the sale, DETM paid a third party net cash payments of $99 million related to the sale of these assets which are included in Cash Flows from Operating Activities. This resulted in a net loss of $65 million. Other significant sales included Duke Energy Royal LLC’s interest in six energy service agreements and DukeSolutions Huntington Beach, LLC, and DEM’s 15% ownership interest in Caribbean Nitrogen Company. DEM also sold its refined products operation in the Eastern United States. Spectra Energy Capital received approximately $58 million from the sale or collection of all of Duke Capital Partners LLC notes receivable, which resulted in an immaterial gain.
Impairments. Field Services.In December 2004, based upon management’s assessment of the probable disposition of some plant and transportation assets in Wyoming, Field Services wrote down the book value of those assets by $4 million ($3 million net of minority interest) to $10 million, which represented the estimated fair value less cost to sell. In February 2005, these assets were exchanged for certain gathering assets in Oklahoma of equivalent fair value.
In September 2004, Field Services recorded a pre-tax impairment charge of approximately $23 million ($16 million net of minority interest) related to management’s current assessment of some additional gathering, processing, compression and transportation assets in Wyoming being held for sale. The estimated fair value of these assets less cost to sell was $27 million. 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.
Crescent. In the fourth quarter of 2004, Crescent recorded pre-tax 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 had 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 pre-tax bad debt charges of $8 million related to notes receivable due from Rim Golf Investor, LLC and Chaparral Pines Investor, LLC.
International Energy. In order to eliminate exposure to international markets outside of Latin America and Canada, International Energy decided in 2003 to pursue a possible sale or Initial Public Offering (IPO) 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 the fourth quarter of 2003, which represented the excess of the carrying value over the estimated fair value of the business, less estimated costs to sell. 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 which restored the loss recorded during the fourth quarter of 2003.
In the second quarter of 2004, International Energy completed the sale of the Asia-Pacific Business to Alinta Ltd. for a gross sales price of approximately $1.2 billion. 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 Asia-Pacific Business.
International Energy held a receivable from Norsk Hydro ASA (Norsk) related to the 2003 sale of International Energy’s European business. In 2004, International Energy recorded a $14 million pre-tax
119
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
allowance against the carrying value of the note based on management’s assessment of the probability of not collecting the entire note. In first quarter 2006, based on management’s best estimate of recoverability, International Energy recorded a pre-tax allowance of approximately $19 million against this receivable. During the second quarter of 2006, International Energy and Norsk signed a settlement agreement in which Norsk agreed to pay International Energy approximately $34 million in full settlement of International Energy’s receivable. In connection with this settlement, International Energy recorded an approximate $9 million pre-tax write-up of the receivable through a reduction in the valuation allowance. In July 2006, International Energy received the settlement proceeds.
13. Property, Plant and Equipment
| Estimated Useful Life | December 31, | |||||||||
| 2006 | 2005 | |||||||||
| (Years) | (in millions) | |||||||||
Land | — | $ | 156 | $ | 264 | |||||
Plant—Regulated | ||||||||||
Natural gas transmission and distribution | 20–82 | 11,018 | 10,810 | |||||||
Gathering and processing facilities(a) | 20–25 | 1,616 | 1,570 | |||||||
Storage | 11–122 | 882 | 717 | |||||||
Other buildings and improvements(a) | 16–50 | 74 | 70 | |||||||
Plant—Unregulated | ||||||||||
Electric generation(a) | 20–50 | — | 3,899 | |||||||
Natural gas transmission and distribution | 20–82 | 24 | 32 | |||||||
Gathering and processing facilities | 20–25 | 760 | 678 | |||||||
Other buildings and improvements(a) | 16–50 | 2 | 27 | |||||||
Equipment(a) | 3–40 | 319 | 446 | |||||||
Vehicles | 3–20 | 86 | 97 | |||||||
Construction in process | — | 306 | 415 | |||||||
Other(a) | 5–122 | 396 | 316 | |||||||
Total property, plant and equipment | 15,639 | 19,341 | ||||||||
Total accumulated depreciation—regulated(b) | (3,069 | ) | (2,758 | ) | ||||||
Total accumulated depreciation—unregulated(b) | (176 | ) | (897 | ) | ||||||
Total net property, plant and equipment | $ | 12,394 | $ | 15,686 | ||||||
| (a) | Includes capitalized leases: total of $4 million for 2006 and $48 million for 2005. |
| (b) | Includes accumulated amortization of capitalized leases: total of $1 million for 2006 and $19 million for 2005. |
Capitalized interest, which includes the interest expense component of AFUDC, amounted to $35 million for 2006, $41 million for 2005, and $36 million for 2004.
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
14. Debt and Credit Facilities
Summary of Debt and Related Terms
| Weighted- Average Rate | Year Due | December 31, | |||||||||||
| 2006 | 2005 | ||||||||||||
| (in millions) | |||||||||||||
Unsecured debt | 7.0 | % | 2007–2036 | $ | 7,437 | $ | 8,857 | ||||||
Secured debt | 6.6 | % | 2007–2019 | 807 | 1,270 | ||||||||
Capital leases | 6.7 | % | 2009 | 3 | 10 | ||||||||
Other debt | — | 19 | 29 | ||||||||||
Commercial paper(a) | 5.5 | % | 349 | 83 | |||||||||
Fair value hedge carrying value adjustment | 2008–2018 | 13 | 21 | ||||||||||
Unamortized debt discount and premium, net | (3 | ) | (3 | ) | |||||||||
Total debt(b) | 8,625 | 10,267 | |||||||||||
Current maturities of long-term debt | (550 | ) | (1,394 | ) | |||||||||
Short-term notes payable and commercial paper(c) | (349 | ) | (83 | ) | |||||||||
Total long-term debt | $ | 7,726 | $ | 8,790 | |||||||||
| (a) | The weighted-average days to maturity were 22 days as of December 31, 2006 and 3 days as of December 31, 2005. |
| (b) | As of December 31, 2006 and 2005, $3,820 million and $3,917 million of debt were denominated in Canadian dollars, respectively. As of December 31, 2005, $501 million of debt was denominated in Brazilian Reals. |
| (c) | Weighted-average rates on outstanding short-term notes payable and commercial paper was 5.5% as of December 31, 2006 and 3.3% as of December 31, 2005. |
Unsecured Debt. In November 2006, Union Gas issued 125 million Canadian dollars of 4.85% fixed-rate debentures (approximately $108 million U.S. dollar equivalents as of the closing date) due in 2022.
In September 2006, prior to the completion of the joint venture transaction of Crescent, as discussed in Note 2, the Crescent JV, Crescent and Crescent’s subsidiaries borrowed approximately $1.23 billion principal amount of debt. The net proceeds from the debt issuance of approximately $1.21 billion were recorded as a cash inflow within Financing Activities on the Consolidated Statements of Cash Flows and were distributed to Spectra Energy Capital. As a result of Spectra Energy Capital’s deconsolidation of Crescent effective September 7, 2006, Crescent’s outstanding debt balance of $1,298 million was removed from Spectra Energy Capital’s Consolidated Balance Sheets.
In September 2006, Union Gas issued 165 million Canadian dollars of 5.46% fixed-rate debentures (approximately $148 million in U.S. dollar equivalents as of the issuance date) due in 2036.
In November 2005, International Energy issued floating rate debt in Guatemala for $87 million (in USD) and in El Salvador for $75 million (in USD). These debt issuances have variable interest rate terms and mature in 2015. This debt was transferred by Spectra Energy Capital to Duke Energy in December 2006 (see Note 1).
On September 21, 2005, Union Gas issued 200 million Canadian dollars of 4.64% fixed-rate debentures (approximately $171 million in U.S. dollar equivalents as of the issuance date) due in 2016.
In August 2005, International Energy issued project-level debt in Peru, of which $75 million is denominated in U.S. dollars and approximately $34 million (in U.S. dollar equivalents as of the issuance date) is denominated in Peru Nuevos Soles. This debt was transferred to Duke Energy in December 2006 (see Note 1).
On March 1, 2005, redemption notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. These bonds were redeemed on April 15, 2005 at a redemption price of 104.03 or approximately $104 million.
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Additionally, Spectra Energy 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. Spectra Energy 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 Duke Energy’s 8% Equity Units in November 2004.
Secured Debt. Other Assets Pledged as Collateral. As of December 31, 2006, secured debt consisted of project financing for Maritimes & Northeast Pipeline, LLC, and Maritimes & Northeast Pipeline, LP (collectively, M&N Pipeline). A portion of the assets, ownership interest and business contracts are pledged as collateral.
Floating Rate Debt. Unsecured debt, secured debt and other debt included approximately $815 million of floating-rate debt as of December 31, 2006, and $1,213 million as of December 31, 2005. As of December 31, 2005, $488 million of Brazilian debt that is indexed annually to Brazilian inflation was included in floating rate debt. Other 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, 2006 and 2005, the average interest rate associated with floating-rate debt was approximately 5.4% and 7.2%, respectively.
Maturities, Call Options and Acceleration Clauses.
Annual Maturities as of December 31, 2006
| (in millions) | |||
2007 | $ | 550 | |
2008 | 295 | ||
2009 | 1,001 | ||
2010 | 756 | ||
2011 | 372 | ||
Thereafter | 5,302 | ||
Total long-term debt(a) | $ | 8,276 | |
| (a) | Excludes short-term notes payable and commercial paper of $349 million. |
Spectra Energy Capital has the ability under certain debt facilities to call and repay the obligation prior to its scheduled maturity. Therefore, the actual timing of future cash repayments could be materially different than the above.
Available Credit Facilities and Restrictive Debt Covenants. During the year ended December 31, 2006, Spectra Energy Capital terminated an $800 million syndicated credit facility and $710 million in bi-lateral credit facilities, offset by the addition of a new $350 million syndicated credit facility. The terminations of these credit facilities primarily reflect Spectra Energy Capital’s reduced liquidity needs as a result of exiting the former DENA business (see Note 12).
The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the available credit facilities.
Spectra Energy Capital’s debt and 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, 2006, Spectra Energy Capital was in compliance with those covenants. In
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
addition, credit agreements allow for acceleration of payments or termination of the agreements due to nonpayment, or in some cases, due to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.
Maritimes & Northeast Pipeline L.P. debt agreements, which had approximately $224 million outstanding at December 31, 2006, require that a deliverability report prepared by an Independent Reserve Engineer on the status of natural gas reserves be provided to the lender’s collateral agent and note trustee prior to November 27, 2007. Should this report demonstrate a sufficient level of natural gas reserves, no action will be required. If the report indicates an insufficient level of reserves, the loan agreements require that certain amounts be escrowed until sufficient cash balances have been built to retire the full amount of the associated outstanding debt at maturity or until a later report is provided indicating that reserves are available in quantities sufficient to eliminate the need to maintain such amounts in escrow.
Credit Facilities Summary as of December 31, 2006 (in millions)
| Amounts Outstanding | ||||||||||||||
| Expiration Date | Credit Facilities Capacity | Commercial Paper | Letters of Credit | Total | ||||||||||
Spectra Energy Capital LLC | ||||||||||||||
$600 multi-year syndicated(a), (b) | June 2010 | $ | 600 | $ | — | $ | 13 | $ | 13 | |||||
$350 364-day syndicated(b) | November 2007 | 350 | 349 | — | 349 | |||||||||
Total Spectra Energy Capital LLC | 950 | 349 | 13 | 362 | ||||||||||
Westcoast Energy Inc. | ||||||||||||||
$173 multi-year syndicated(c) | June 2011 | 173 | — | — | — | |||||||||
Union Gas Limited | ||||||||||||||
$345 364-day syndicated(d) | June 2007 | 345 | — | — | — | |||||||||
Total(g) | $ | 1,468 | $ | 349 | $ | 13 | $ | 362 | ||||||
| (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 is denominated in Canadian dollars totaling 200 million Canadian dollars and contains a covenant that requires the debt-to-total capitalization ratio to not exceed 75%. |
| (d) | Credit facility is denominated in Canadian dollars totaling 400 million Canadian dollars and contains a covenant that requires the debt-to-total capitalization ratio to not exceed 75% and 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. |
Spectra Energy Capital has approximately $695 million of credit facilities which expire in 2007, that are expected to be replaced.
15. Preferred and Preference Stock at Spectra Energy Capital’s Subsidiaries
In connection with the Westcoast acquisition in 2002, Spectra Energy Capital assumed preferred and preference shares at Westcoast and Union Gas. These preferred and preference shares at Westcoast and Union Gas totaled $225 million at both December 31, 2006 and 2005. 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, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” As such, these preferred and preference shares are considered contingently redeemable shares and are included in Minority Interests on the Consolidated Balance Sheets.
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
16. Commitments and Contingencies
General Insurance
Spectra Energy Capital carries, either directly or through Duke Energy’s captive insurance company, Bison, and its affiliates, insurance and reinsurance coverages consistent with companies engaged in similar commercial operations with similar type properties. Spectra Energy 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 Spectra Energy 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) insurance policies in support of the indemnification provisions of Spectra Energy Capital’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 extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.
Spectra Energy 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 Spectra Energy Capital’s general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.
As of January 2007, subsequent to the spin-off of Spectra Energy from Duke Energy, Spectra Energy Capital has its own captive insurance company that will provide similar coverage to that previously provided by Duke Energy.
Environmental
Spectra Energy Capital is subject to international, federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These regulations can be changed from time to time, imposing new obligations on Spectra Energy Capital.
Remediation activities. Like others in the energy industry, Spectra Energy Capital and its affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of ongoing Spectra Energy Capital operations, sites formerly owned or used by Spectra Energy Capital entities, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with 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, Spectra Energy Capital or its affiliates could potentially be held responsible for contamination caused by other parties. In some instances, Spectra Energy 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 Spectra Energy Capital’s consolidated results of operations, cash flows or financial position.
Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets were total accruals related to extended environmental-related activities of approximately $21 million and $50 million as of December 31, 2006 and 2005, respectively. These accruals represent Spectra Energy Capital’s provisions for costs associated with remediation activities at some of its current and former sites, as well as other relevant environmental contingent liabilities. Management believes that completion or resolution of these matters will have no material adverse effect on Spectra Energy Capital’s consolidated results of operations, cash flows or financial position.
124
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Litigation
In connection with the transfer of certain businesses from Spectra Energy Capital to Duke Energy in December 2006, certain litigation matters that had previously involved Spectra Energy Capital were transferred to Duke Energy. Spectra Energy Capital does not have any future exposure or obligations related to such matters, and accordingly, such matters are not discussed below.
Sonatrach/Sonatrading Arbitration. In an arbitration proceeding that commenced in January 2001 in London, Duke Energy LNG Sales Inc. (Duke LNG) claimed 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 by LNG tanker to Lake Charles, Louisiana. Duke LNG sought damages of approximately $27 million. Sonatrading and Sonatrach claimed that Duke LNG had repudiated the LNG Agreements by allegedly failing to diligently perform LNG marketing obligations. Sonatrading and Sonatrach sought damages of approximately $250 million. In 2003, the arbitration tribunal issued a Partial Award on liability issues and found that Sonatrach and Sonatrading breached their obligations to provide shipping. The tribunal also found that Duke LNG breached the LNG Purchase Agreement by failing to perform marketing obligations. A hearing on damages was concluded in March 2006, and the tribunal issued its award on damages on November 30, 2006. Duke LNG was awarded approximately $20 million, plus interest, for Sonatrach’s breach of its shipping obligations. Sonatrach and Sonatrading were awarded an unspecified amount that management believes will, when calculated, be substantially less than the amount awarded to Duke LNG, and result ultimately in a net positive, but immaterial, award to Duke LNG. Duke LNG’s rights and obligations pertaining to this matter were retained by Spectra Energy Capital in connection with the spin-off in January 2007.
Citrus Trading Corporation (Citrus) Litigation. On March 7, 2003, Citrus Trading Corp. (Citrus) filed a lawsuit against Duke Energy LNG Sales, Inc. (Duke LNG). The petition alleged that Duke LNG had breached the parties’ natural gas purchase contract dated December 22, 1998 (the Agreement) by failing to provide sufficient volumes of gas to Citrus. Duke LNG asserted that it had experienced a loss of LNG supply as a result of breaches of contract by its LNG supplier and transporter, Sonatrading Amsterdam B.V. (Sonatrading) and its parent company, Sonatrach, the Algerian State-owned energy company, and that this loss of LNG supply affected Duke LNG’s obligations and termination rights under the Agreement.
On April 14, 2003, following commencement of the Citrus lawsuit, Duke LNG terminated the Agreement on the grounds, among others, that Citrus failed to make a quarterly adjustment in the amount of its letter of credit as required under the Agreement. On April 16, 2003, Duke LNG filed a counterclaim demanding declaratory relief and unspecified damages for Citrus’ breach of the Agreement. Citrus denied that Duke LNG had the right to terminate the Agreement and claimed that Duke LNG’s termination of the Agreement was itself a breach entitling Citrus to resulting damages of approximately $190 million (excluding interest). On March 16, 2004, Citrus filed suit against PanEnergy Corp in the District Court of Harris County, Texas alleging that PanEnergy is financially responsible for losses incurred by Citrus as a result of Duke LNG’s alleged breaches. That state Court action was removed and consolidated with the action against Duke LNG in federal court. All liabilities associated with this litigation were assumed by Spectra Energy in connection with its spin-off from Duke Energy. Spectra Energy Capital had recorded a charge within Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations of $100 million in December 2006 related to this matter. On January 29, 2007, Spectra Energy and Citrus entered into a binding agreement to settle this litigation for a payment by Spectra to Citrus in the amount of $100 million. The settlement payment was tendered to Citrus on January 30, 2007 and the lawsuit was subsequently dismissed with prejudice.
Duke Energy Retirement Cash Balance Plan. A class action lawsuit was filed in federal court in South Carolina against Duke Energy and the Duke Energy Retirement Cash Balance Plan. Six causes of action are alleged, including violations of the Employee Retirement Income Security Act of 1974 (ERISA) and the Age Discrimination in Employment Act. These allegations arise out of the conversion of the Duke Power Company
125
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Employees’ Retirement Plan into the Duke Power Company Retirement Cash Balance Plan. The plaintiffs seek to represent present and former participants in the Duke Energy Retirement Cash Balance Plan. This group is estimated to include approximately 36,000 persons. Duke Energy filed its answer in March 2006. A second class action lawsuit was filed in federal court in South Carolina, alleging similar claims and seeking to represent the same class of defendants. The second case has been voluntarily dismissed, without prejudice, effectively consolidating it with the first case. It is not possible to predict with certainty whether Spectra Energy Capital will incur any liability or to estimate the damages, if any, that might be incurred in connection with this matter. Spectra Energy Capital has agreed to share these liabilities with Duke Energy in connection with the spin-off in January 2007.
Other Litigation and Legal Proceedings. Spectra Energy Capital and its subsidiaries are involved in other legal, tax and regulatory proceedings in various forums arising in the ordinary course of business regarding contract, royalty, measurement and payment claims, some of which involve substantial monetary amounts. Management believes that the final disposition of these proceedings will not have a material adverse effect on Spectra Energy Capital’s consolidated results of operations, cash flows or financial position.
Spectra Energy Capital has exposure to certain legal matters that are described herein. As of December 31, 2006, and December 31, 2005, Spectra Energy Capital has recorded reserves of approximately $100 million and $150 million, respectively, for these proceedings and exposures, respectively. Spectra Energy Capital has insurance coverage for certain of these losses should they be incurred. These reserves represent management’s best estimate of probable loss as defined by SFAS No. 5, “Accounting for Contingencies.”
Spectra Energy Capital expenses legal costs related to the defense of loss contingencies as incurred.
Other Commitments and Contingencies
Algonquin is a 50% equity partner in the Islander East pipeline project, a proposed pipeline that would connect natural gas supplies to markets on Long Island, New York. This project has received FERC and other approvals, and is pending receipt of a Section 401 Water Quality Certificate from the State of Connecticut, which has been denied by the State and is the subject of an appeal before the 2nd Circuit Court of Appeals. Oral arguments on the appeal are scheduled to be heard in April 2007. Management believes that there are sufficient factual and legal bases supporting Spectra Energy Capital’s position that the State’s denial of certificate was improper. However, if the State’s position is ultimately upheld, Islander East and Algonquin will be unable to proceed with the project as it is currently configured. As of December 31, 2006, Islander East, owned 50% by Algonquin, had incurred development costs of approximately $61 million, and Algonquin had incurred development costs of approximately $19 million, all associated with the Islander East project. Management expects that certain of the development costs incurred to date, primarily purchased materials, could be utilized by other capital projects of Spectra Energy Capital.
As part of its normal business, Spectra Energy 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. These arrangements are largely entered into by Spectra Energy Capital. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Spectra Energy 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. For further information see Note 17.
In addition, Spectra Energy Capital enters into various fixed-price, non-cancelable commitments to purchase transportation or throughput agreements and other contracts that may or may not be recognized on the Consolidated Balance Sheets.
126
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Operating and Capital Lease Commitments
Spectra Energy Capital leases assets in several areas of its operations. Consolidated rental expense for operating leases classified in Income (Loss) From Continuing Operations was $36 million in 2006, $53 million in 2005 and $64 million in 2004, which is included in Operation, Maintenance and Other on the Consolidated Statements of Operations. For years ended December 31, 2006, 2005 and 2004, Spectra Energy Capital recorded pre-tax consolidated rental expense for operating leases classified in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations of $37 million, $27 million and $15 million, respectively. Amortization of assets recorded under capital leases included in continuing operations 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, 2006:
| Operating Leases | Capital Leases | |||||
| (in millions) | ||||||
2007 | $ | 30 | $ | 1 | ||
2008 | 27 | 1 | ||||
2009 | 26 | 1 | ||||
2010 | 23 | — | ||||
2011 | 20 | — | ||||
Thereafter | 71 | — | ||||
Total future minimum lease payments | $ | 197 | $ | 3 | ||
17. Guarantees and Indemnifications
Spectra Energy 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. Spectra Energy Capital and its subsidiaries enter into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party.
Spectra Energy 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. In contemplation of the spin-off (see Note 1), certain guarantees that were previously issued by Spectra Energy Capital were transferred to Duke Energy in 2006. For remaining guarantees of other Duke Energy obligations that are yet to be assigned, Duke Energy has indemnified Spectra Energy Capital against any losses incurred under these guarantee arrangements. As of December 31, 2006, Spectra Energy Capital had certain guarantees of Duke Energy subsidiaries that became guarantees of third-party performance upon separation from Duke Energy.
The maximum potential amount of future payments Spectra Energy Capital could have been required to make under these performance guarantees as of December 31, 2006 was approximately $615 million, of which approximately $215 million has been indemnified by Duke Energy, as discussed above. Of this amount, approximately $25 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $40 million of the performance guarantees expire between 2007 and 2009, with the remaining performance guarantees expiring after 2009 or having no contractual expiration.
Additionally, Spectra Energy 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. Substantially all of these guarantees have no contractual expiration and no stated maximum amount of future payments that Spectra Energy 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.
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Westcoast has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method investments, 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 such unconsolidated or sold 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, 2006 was approximately $51 million. Of those guarantees, approximately $10 million expire in 2007, with the remainder having no contractual expiration.
A subsidiary of Natural Gas Transmission has issued guarantees of debt and performance guarantees associated with non-consolidated entities and less than wholly owned consolidated entities. If such entities were to default on payments or performance, Natural Gas Transmission would be required under the guarantees to make payment on the obligation of the less than wholly owned entity. As of December 31, 2006, Natural Gas Transmission was the guarantor of approximately $17 million of debt at Westcoast associated with less than wholly owned entities, which expire in 2019.
Spectra Energy 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, Spectra Energy 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 of future payments Spectra Energy Capital could have been required to make under these letters of credit as of December 31, 2006 was approximately $13 million.
In 1999, the Industrial Development Corp of the City of Edinburg, Texas (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo (Hidalgo), a subsidiary of Duke Energy. Spectra Energy Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Spectra Energy Capital remained obligated under the lease guaranty. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Gross, undiscounted exposure under the guarantee obligation as of December 31, 2006 is approximately $200 million, including principal and interest payments. Spectra Energy Capital does not believe a loss under the guarantee obligation is probable as of December 31, 2006, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of December 31, 2006. No demands for payment have been made under the guarantee. If losses are incurred under the guarantee, Spectra Energy Capital has certain rights which should allow it to mitigate such loss. Subsequent to the spin-off of Spectra Energy by Duke Energy, this guarantee remained with Spectra Energy Capital. However, Duke Energy indemnified Spectra Energy Capital against any future losses that could arise from payments required under this guarantee.
Spectra Energy 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. Spectra Energy Capital’s potential exposure under these indemnification agreements can range from a specified amount, such as the purchase price, to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Spectra Energy Capital is unable to estimate the total potential amount of future payments under these indemnification agreements due to several factors, such as the unlimited exposure under certain guarantees.
At December 31, 2006, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
18. Stock-Based Compensation
Effective January 1, 2006, Spectra Energy Capital adopted the provisions of SFAS No. 123(R). SFAS No. 123(R) establishes accounting for stock-based awards exchanged for employee and certain nonemployee services. Accordingly, for employee awards, equity classified stock-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as expense over the requisite service period. Spectra Energy Capital is allocated stock-based compensation expense from Duke Energy as certain of its employees participate in Duke Energy’s stock-based compensation programs. Prior to the adoption of SFAS 123(R), Spectra Energy Capital applied 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 25)” and provided the required pro forma disclosures of SFAS No. 123. Since the exercise price for all options granted under those plans was equal to the market value of the underlying common stock on the grant date, no compensation cost was recognized in the accompanying Consolidated Statements of Operations.
Spectra Energy Capital elected to adopt the modified prospective application method as provided by SFAS No. 123(R), and accordingly, financial statement amounts from the prior periods presented in this Form 10-K have not been restated. There were no modifications to outstanding stock options prior to the adoption of SFAS 123(R).
Spectra Energy Capital recorded pre-tax stock-based compensation expense included in continuing operations for the years ended December 31, 2006, 2005 and 2004 as follows, the components of which are further described below:
| For the Years Ended December 31, | |||||||||
| 2006 | 2005 | 2004 | |||||||
| (in millions) | |||||||||
Stock Options | $ | 2 | $ | — | $ | — | |||
Stock Appreciation Rights | 2 | 1 | 1 | ||||||
Phantom Stock | 7 | 5 | 3 | ||||||
Performance Awards | 7 | 6 | 3 | ||||||
Other Stock Awards | — | — | 1 | ||||||
Total | $ | 18 | $ | 12 | $ | 8 | |||
The tax benefit in income from continuing operations associated with the recorded expense for the years ended December 31, 2006, 2005 and 2004 was approximately $7 million, $4 million and $3 million, respectively. Excluded from amounts above are pre-tax stock-based compensation expense of approximately $31 million, $26 million and $14 million for the years ended December 31, 2006, 2005 and 2004, respectively, that is included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations. The tax benefit associated with the amounts that are in Income (Loss) From Discontinued Operations, net of tax, for the years ended December 31, 2006, 2005 and 2004 are approximately $11 million, $10 million and $5 million, respectively. There were no material differences in income from continuing operations, income tax expense, net income or cash flows from the adoption of SFAS No. 123(R).
The following table shows what net income (loss) would have been for Spectra Energy Capital if Duke Energy had applied the fair value recognition provisions of SFAS No. 123(R) to all stock-based compensation awards during prior periods.
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Pro Forma Stock-Based Compensation
Year ended December 31, 2005 | Year ended December 31, 2004 | |||||||
| (in millions ) | ||||||||
Net income (loss), as reported | $ | 674 | $ | (114 | ) | |||
Add: stock-based compensation expense included in reported net income (loss), net of related tax effects | 24 | 14 | ||||||
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects | (26 | ) | (22 | ) | ||||
Pro forma net income (loss), net of related tax effects | $ | 672 | $ | (122 | ) | |||
Duke Energy’s 2006 Long-term Incentive Plan (the 2006 Plan), approved by shareholders in October 2006, reserved 60 million shares of common stock for awards to employees and outside directors. 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. The 2006 Plan supersedes the 1998 Plan and no additional grants will be made from the 1998 Plan. Under the 2006 Plan and 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. Duke Energy has historically issued new shares upon exercising or vesting of share-based awards.
Upon the acquisition of Westcoast in 2002, 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.
Stock Option Activity
Options (in thousands) | Weighted- Average Exercise Price | �� | Weighted- Average Life (in years) | Aggregate Intrinsic Value (in millions) | ||||||
Outstanding at December 31, 2005 | 19,493 | $ | 29 | |||||||
Employee transfers into Spectra Energy Capital, net of transfers out | 612 | 31 | ||||||||
Exercised | (3,299 | ) | 24 | |||||||
Forfeited or expired | (1,117 | ) | 35 | |||||||
Options held by employees transferred to Duke Energy in December 2006 | (8,334 | ) | 32 | |||||||
Outstanding at December 31, 2006 | 7,355 | 28 | 4.3 | $56 | ||||||
Exercisable at December 31, 2006 | 5,865 | $31 | 3.7 | $31 | ||||||
Options Expected to Vest | 1,479 | $17 | 6.7 | $25 | ||||||
On December 31, 2005 and 2004, Spectra Energy Capital employees had approximately 16 million and 17 million exercisable options, respectively with a $32 weighted-average exercise price. The total intrinsic value of options exercised during the years ended December 31, 2006, 2005 and 2004 was approximately $22 million, $14 million and $6 million, respectively. Cash received by Duke Energy from options exercised during the year ended December 31, 2006 was approximately $79 million, with a related tax benefit to Duke Energy of approximately $8 million. At December 31, 2006, Spectra Energy Capital had less than $1 million of future compensation cost which is expected to be recognized over a weighted-average period of less than one year.
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
There were no options granted to Spectra Energy Capital employees during the years ended December 31, 2006, 2005 and 2004.
The 2006 Plan allows for a maximum of 15 million shares of common stock to be issued under various stock-based awards other than options and stock appreciation rights. The 1998 Plan allows for a maximum of 12 million shares of common stock to be issued under various stock-based awards. Payments for cash settled awards during the period were immaterial.
Performance Awards
Stock-based performance awards outstanding under the 1998 Plan generally vest over three years. Vesting for certain stock-based performance awards can occur in three years, at the earliest, if performance is met. Certain performance awards granted in 2006 contain market conditions based on the total shareholder return (TSR) of Duke Energy stock relative to a pre-defined peer group (relative TSR). These awards are valued using a path-dependent model that incorporates expected relative TSR into the fair value determination of Duke Energy’s performance-based share awards with the adoption of SFAS No. 123(R). The model uses three year historical volatilities and correlations for all companies in the pre-defined peer group, including Duke Energy, to simulate Duke Energy’s relative TSR as of the end of the performance period. For each simulation, Duke Energy’s relative TSR associated with the simulated stock price at the end of the performance period plus expected dividends within the period results in a value per share for the award portfolio. The average of these simulations is the expected portfolio value per share. Actual life to date results of Duke Energy’s relative TSR for each grant is incorporated within the model. Other awards not containing market conditions are measured at grant date price. Duke Energy awarded 790,230 shares (fair value of approximately $14 million) to employees of Spectra Energy Capital in the year ended December 31, 2006, 1,005,020 shares (fair value of approximately $27 million, based on the market price of Duke Energy’s common stock at the grant date) to Spectra Energy employees in the year ended December 31, 2005, and 1,442,140 shares (fair value of approximately $31 million, based on the market price of Duke Energy’s common stock at the grant date) to employees of Spectra Energy Capital in the year ended December 31, 2004.
The following table summarizes information about stock-based performance awards outstanding at December 31, 2006:
| Shares | Weighted Average Grant Date Fair Value | |||||
Number of Stock-based Performance Awards: | ||||||
Outstanding at December 31, 2005 | 2,351,972 | $ | 25 | |||
Granted | 790,230 | 18 | ||||
Vested | (114,000 | ) | 27 | |||
Forfeited | (109,692 | ) | 25 | |||
Awards held by employees transferred to Duke Energy in December 2006 | (1,553,400 | ) | 22 | |||
Outstanding at December 31, 2006 | 1,365,110 | $ | 25 | |||
Stock-based Performance Awards Expected to Vest | 1,308,731 | $ | 25 | |||
The total fair value of the shares vested during the year ended December 31, 2006 and 2005 was approximately $3 million. As of December 31, 2006, Spectra Energy Capital had approximately $8 million of future compensation cost which is expected to be recognized over a weighted-average period of less than one year.
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Phantom Stock Awards
Phantom stock awards outstanding under the 1998 Plan generally vest over periods from immediate to five years. Duke Energy awarded 582,040 shares (fair value of approximately $17 million) to Spectra Energy Capital employees based on the market price of Duke Energy’s common stock at the grant dates in the year ended December 31, 2006, 924,170 shares (fair value of approximately $25 million) in the year ended December 31, 2005, and 1,169,090 shares (fair value of approximately $25 million) in the year ended December 31, 2004.
The following table summarizes information about phantom stock awards outstanding at December 31, 2006:
| Shares | Weighted Average Grant Date Fair Value | |||||
Number of Phantom Stock Awards: | ||||||
Outstanding at December 31, 2005 | 2,009,641 | $ | 25 | |||
Granted | 582,040 | 29 | ||||
Vested | (664,583 | ) | 25 | |||
Forfeited | (88,407 | ) | 26 | |||
Awards held by employees transferred to Duke Energy in December 2006 | (999,543 | ) | 26 | |||
Outstanding at December 31, 2006 | 839,148 | $ | 28 | |||
Phantom Stock Awards Expected to Vest | 805,895 | $ | 28 | |||
The total fair value of the shares vested during the years ended December 31, 2006, 2005 and 2004 was approximately $16 million, $9 million and $6 million, respectively. As of December 31, 2006, Spectra Energy Capital had approximately $7 million of future compensation cost which is expected to be recognized over a weighted-average period of 3.0 years.
Other Stock Awards
Other stock awards outstanding under the 1998 Plan generally vest over periods from three to five years. Duke Energy awarded 41,000 shares (fair value of approximately $1 million) to Spectra Energy Capital employees based on the market price of Duke Energy’s common stock at the grant dates in the year ended December 31, 2006, 47,000 shares (fair value of approximately $1 million) in the year ended December 31, 2005, and 169,160 shares (fair value of approximately $4 million) in the year ended December 31, 2004.
The following table summarizes information about other stock awards outstanding at December 31, 2006:
| Shares | Weighted Average Grant Date Fair Value | |||||
Number of Other Stock Awards: | ||||||
Outstanding at December 31, 2005 | 122,937 | $ | 25 | |||
Granted | 41,000 | 29 | ||||
Vested | (18,630 | ) | 24 | |||
Forfeited | (10,200 | ) | 33 | |||
Awards held by employees transferred to Duke Energy in December 2006 | (63,680 | ) | 28 | |||
Outstanding at December 31, 2006 | 71,427 | $ | 27 | |||
Other Stock Awards Expected to Vest | 66,263 | $ | 27 | |||
The total fair value of the shares vested during the years ended December 31, 2006, 2005 and 2004 was less than $1 million, less than $1 million and approximately $1 million, respectively. As of December 31, 2006, Spectra Energy Capital had less than $1 million of future compensation cost which is expected to be recognized over a weighted-average period of 1.2 years.
132
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Impact of Spin-off on Equity Compensation Awards of Employees of Spectra Energy Capital
As discussed in Note 1, on January 2, 2007, Spectra Energy, consisting principally of the operations of Spectra Energy Capital, was spun-off by Duke Energy to its shareholders. In connection with this transaction, Duke Energy distributed substantially all the shares of common stock of Spectra Energy to Duke Energy shareholders. The distribution ratio approved by Duke Energy’s Board of Directors was one-half share of Spectra Energy common stock for every share of Duke Energy common stock.
Effective with the spin-off, all previously granted Duke Energy long-term incentive plan equity awards were split into Duke Energy and Spectra Energy equity-related awards, consistent with the spinoff conversion ratio. Each equity award (stock option, phantom share, performance share and restricted stock award) was split into two awards: a Duke Energy award (issued by Duke Energy in Duke Energy shares) and a Spectra Energy award (issued by Spectra Energy in Spectra Energy shares). The number of shares covered by the Duke Energy adjusted award equal the number of shares covered by the original award, and the number of shares covered by the adjusted Spectra Energy award equal the number of shares that would have been received in the spinoff by a non-employee shareholder.
Stock option exercise prices were adjusted using a formula approved by the Duke Energy Compensation Committee that was designed to preserve the spread (whether “in the money” or “under water”) of each option.
All equity award adjustments were designed to equalize the fair value of each award before and after the spinoff. Accordingly, no additional compensation expense of significance resulted at the spinoff date as a result of the equity award adjustments.
Spectra Energy Capital’s future stock-based compensation expense will not be significantly impacted by the equity award adjustments that occurred as a result of the spinoff. Stock-based compensation expense recognized in future periods will correspond to the unamortized portion as of the spin-off of the original grant date fair value of the equity awards held by Spectra Energy Capital employees (regardless whether those awards are linked to Duke Energy stock or Spectra Energy stock).
| 19. | Employee Benefit Plans |
Duke Energy U.S. Retirement Plans. Up until the January 2, 2007 spin-off of the natural gas businesses by Duke Energy, Spectra Energy Capital and its subsidiaries participate in Duke Energy’s qualified 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.
Spectra Energy Capital’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 did not make any contributions to its defined benefit retirement plan in 2006 or 2005. Duke Energy made voluntary contributions of $250 million in 2004.
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 retirement plan is 11 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.
Effective with the separation from Duke Energy, Spectra Energy established a new non-contributory defined benefit retirement plan in which Spectra Energy Capital and its subsidiaries participate. In accordance with the separation agreement with Duke Energy, plan assets and liabilities associated with the employees and operations of Spectra Energy were transferred to Spectra Energy in January 2007. Benefits provided are substantially the same as those previously provided by Duke Energy.
133
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Qualified Pension Plans
The fair value of Duke Energy’s U.S. plan assets (excluding Cinergy) was $3,022 million as of September 30, 2006 and $2,948 million as of September 30, 2005. The projected benefit obligation of Duke Energy’s U.S. plans (excluding Cinergy) was $2,847 million as of September 30, 2006 and $2,853 million as of September 30, 2005. The accumulated benefit obligation of Duke Energy’s U.S. plans (excluding Cinergy) was $2,719 million as of September 30, 2006 and $2,753 million at September 30, 2005.
Spectra Energy Capital’s pre-tax net periodic pension benefit for the U.S. plans included in continuing operations, as allocated by Duke Energy, was $1 million for 2006, $4 million for 2005 and $6 million for 2004. These amounts exclude pre-tax pension cost of $11 million, $17 million and $22 million for the years ended December 31, 2006, 2005 and 2004, respectively, related to entities transferred to Duke Energy, which are reflected in Income (Loss) From Discontinued Operations, net of tax, in the Consolidated Statements of Operations (see Note 1).
Non-Qualified Pension Plans
Duke Energy maintains, and Spectra Energy Capital participates in, a non-qualified, non-contributory defined benefit retirement plan which covers certain U.S. executives. There are no plan assets. The projected benefit obligation was $84 million as of September 30, 2006 and $86 million as of September 30, 2005.
Spectra Energy Capital’s pre-tax net periodic pension cost for the U.S. plan, as allocated by Duke Energy, was $1 million for 2006, 2005 and 2004, respectively. These amounts exclude pre-tax pension cost of $3 million, $3 million and $4 million for the years ended December 31, 2006, 2005 and 2004, respectively, related to entities transferred to Duke Energy, which are reflected in Income (Loss) From Discontinued Operations, net of tax, in the Consolidated Statements of Operations (see Note 1).
Duke Energy also sponsors, and Spectra Energy Capital participates in, employee savings plans that cover substantially all U.S. employees. Most employees participate in a matching contribution formula where Duke Energy provides a matching contribution generally equal to 100% of before-tax employee contributions, of up to 6% of eligible pay per pay period. Spectra Energy Capital expensed pre-tax employer matching contributions, as allocated by Duke Energy, of $8 million in 2006, $7 million in 2005 and $7 million in 2004. These amounts exclude pre-tax expenses of $14 million for 2006, $13 million for 2005 and $13 million for 2004, related to entities transferred to Duke Energy, which are reflected in Income (Loss) From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.
Westcoast Canadian Retirement Plans. The Westcoast benefit plans are reported separately due to actuarial assumption differences. Westcoast and its subsidiaries maintain qualified and non-qualified contributory and non-contributory defined benefit (DB) and defined contribution (DC) retirement plans covering substantially all employees of Spectra Energy Capital’s Canadian operations. 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 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’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. Spectra Energy Capital made contributions to the Westcoast DB plans of approximately $44 million in 2006, $42 million in 2005 and $26 million in 2004. Spectra Energy Capital also made contributions to the DC plans of $4 million in 2006, $3 million in 2005 and $3 million in 2004.
134
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
The prior service cost 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 qualified DB retirement plans is 10 years. The average remaining service period of the active employees covered by the non-qualified DB retirement plan is 14 years. Westcoast uses a September 30 measurement date for its plans.
Spectra Energy Capital adopted the disclosure and recognition provisions of SFAS No. 158, effective December 31, 2006. The following table describes the total incremental effect of the adoption of SFAS No. 158 on individual line items in the December 31, 2006 Consolidated Balance Sheet, including Accumulated Other Comprehensive Income.
Incremental Effect of the Adoption of SFAS No. 158 on Individual Line Items in the Consolidated Balance Sheet As of December 31, 2006 for Westcoast
| Before Application of SFAS No. 158 | Adjustment | After Application of SFAS No. 158 | ||||||||||
| (in millions) | ||||||||||||
Accrued pension and other post-retirement liabilities(a) | $ | (223 | ) | $ | (69 | ) | $ | (292 | ) | |||
Intangible Assets | 6 | (6 | ) | — | ||||||||
Pre-funded pension costs | — | — | — | |||||||||
Regulatory Assets | — | — | — | |||||||||
Deferred income tax assets | 32 | 27 | 59 | |||||||||
Accumulated other comprehensive income, net of tax | 61 | 48 | 109 | |||||||||
Total Recognized | $ | (124 | ) | $ | — | $ | (124 | ) | ||||
| (a) | Includes approximately $10 million that is reflected in Other within Current Liabilities in the Consolidated Balance Sheets at December 31, 2006. |
Qualified Pension Plans
Components of Net Periodic Pension Costs for Westcoast: Qualified Pension Plans—for the years ended December 31,
| 2006 | 2005 | 2004 | ||||||||||
| (in millions) | ||||||||||||
Service cost benefit earned during the year | $ | 13 | $ | 9 | $ | 8 | ||||||
Interest cost on projected benefit obligation | 31 | 29 | 26 | |||||||||
Expected return on plan assets | (33 | ) | (27 | ) | (24 | ) | ||||||
Amortization of prior service cost | 1 | 1 | — | |||||||||
Amortization of loss | 10 | 4 | 3 | |||||||||
Special termination benefit cost | — | — | 1 | |||||||||
Net periodic pension costs / (income) | $ | 22 | $ | 16 | $ | 14 | ||||||
135
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Reconciliation of Funded Status to Net Amount Recognized for Westcoast: Qualified Pension Plans—as of December 31,
| 2006 | 2005 | |||||||
| (in millions) | ||||||||
Change in Projected Benefit Obligation | ||||||||
Obligation at prior measurement date | $ | 616 | $ | 480 | ||||
Service cost | 13 | 9 | ||||||
Interest cost | 31 | 29 | ||||||
Actuarial losses / (gains) | 20 | 89 | ||||||
Participant contributions | 3 | 3 | ||||||
Benefits paid | (32 | ) | (28 | ) | ||||
Obligation assumed from acquisition | — | 11 | ||||||
Foreign currency impact | 2 | 23 | ||||||
Obligation at measurement date | $ | 653 | $ | 616 | ||||
Change in Fair Value of Plan Assets | ||||||||
Plan assets at prior measurement date | $ | 475 | $ | 362 | ||||
Actual return on plan assets | 32 | 63 | ||||||
Benefits paid | (32 | ) | (28 | ) | ||||
Employer contributions | 45 | 48 | ||||||
Plan participants’ contributions | 3 | 3 | ||||||
Assets received on acquisition | — | 10 | ||||||
Foreign currency impact | 2 | 17 | ||||||
Plan assets at measurement date | $ | 525 | $ | 475 | ||||
Funded status | $ | (128 | ) | $ | (141 | ) | ||
Unrecognized net experience loss | — | 122 | ||||||
Unrecognized prior service cost | — | 8 | ||||||
Contributions between measurement date and year end | 12 | 13 | ||||||
Net amount recognized | $ | (116 | ) | $ | 2 | |||
For Westcoast, the accumulated benefit obligation was $588 million at September 30, 2006 and $562 million at September 30, 2005.
Qualified Pension Plans—Amounts Recognized in the Consolidated Balance Sheets for Westcoast Consist of:—as of December 31,
| 2006 | 2005 | |||||||
| (in millions) | ||||||||
Accrued pension liability | $ | (116 | ) | $ | (76 | ) | ||
Intangible asset | — | 7 | ||||||
Deferred income tax asset | — | 25 | ||||||
Accumulated other comprehensive income | — | 46 | ||||||
Net amount recognized | $ | (116 | ) | $ | 2 | |||
As a result of the adoption of SFAS No. 158, certain previously unrecognized amounts were recognized in the amounts noted above with an offset to Accumulated Other Comprehensive Income and Deferred Income Taxes as of December 31, 2006. The table below details the components of these balances.
136
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Qualified Pension Plans—Amounts Recognized in Accumulated Other Comprehensive Income for Westcoast Consist of:—as of December 31, 2006 (in millions)
Deferred income tax asset | $ | (49 | ) | |
Prior service cost | 8 | |||
Net actuarial loss | 132 | |||
Net amount recognized – Accumulated other comprehensive income | $ | 91 | ||
At December 31, 2006, approximately $8 million of unrecognized losses and $1 million of unrecognized prior service costs were included in Accumulated Other Comprehensive Income in the Consolidated Balance Sheets that will be recognized in net periodic qualified pension costs in 2007.
Additional Information:
Qualified Pension Plans—Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets for Westcoast:
| 2006 | 2005 | |||||
| (in millions) | ||||||
Projected benefit obligation | $ | 637 | $ | 602 | ||
Accumulated benefit obligation | 576 | 551 | ||||
Fair value of plan assets | 511 | 464 | ||||
Qualified Pension Plans—Assumptions Used for Pension Benefits Accounting for Westcoast
| 2006 | 2005 | 2004 | ||||
| (percentages) | ||||||
Benefit Obligations | ||||||
Discount rate | 5.00 | 5.00 | 6.25 | |||
Salary increase | 3.50 | 3.25 | 3.25 | |||
Net Periodic Benefit Cost | ||||||
Discount rate | 5.00 | 6.25 | 6.00 | |||
Salary increase | 3.25 | 3.25 | 3.25 | |||
Expected long-term rate of return on plan assets | 7.25 | 7.50 | 7.50 | |||
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.
Qualified Pension Plan Assets—Westcoast:
| Target Allocation | Percentage of Plan Assets at September 30 | ||||||||
Asset Category | 2006 | 2005 | |||||||
Canadian equity securities | 30 | % | 29 | % | 42 | % | |||
U.S. equity securities | 15 | 15 | 11 | ||||||
EAFE equity securities(a) | 15 | 16 | 15 | ||||||
Debt securities | 40 | 40 | 32 | ||||||
Total | 100 | % | 100 | % | 100 | % | |||
| (a) | EAFE—Europe, Australasia, Far East |
137
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
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 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 also held for diversification.
The long-term rate of return of 7.25% as of September 30, 2006 for the Westcoast assets was developed using a weighted-average calculation of expected returns based primarily on future expected returns across classes considering the use of active asset managers. The weighted-average returns expected by asset classes were 2.5% for Canadian equities, 1.3% for U.S. equities, 1.4% for Europe, Australasia and Far East equities, and 2.0% for fixed income securities.
The following benefit payments, which reflect expected future service, as appropriate, as expected to be paid over the next five years and thereafter:
Qualified Pension Plans—Expected Westcoast Benefit Payments
| (in millions) | |||
Years Ended December 31, | |||
2007 | $ | 31 | |
2008 | 31 | ||
2009 | 32 | ||
2010 | 33 | ||
2011 | 34 | ||
2012 – 2016 | 201 | ||
Non-Qualified Pension Plans
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).
Components of Net Periodic Pension Costs for Westcoast—for the years ended December 31,
| 2006 | 2005 | 2004 | |||||||
| (in millions) | |||||||||
Service cost benefit earned during the year | $ | 1 | $ | 1 | $ | — | |||
Interest cost on projected benefit obligation | 4 | 4 | 4 | ||||||
Amortization of loss | 1 | — | — | ||||||
Net periodic pension costs / (income) | $ | 6 | $ | 5 | $ | 4 | |||
138
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Non-Qualified Pension Plans- Reconciliation of Funded Status to Net Amount Recognized for Westcoast: as of and for the Years Ended December 31,
| 2006 | 2005 | |||||||
| (in millions) | ||||||||
Change in Projected Benefit Obligation | ||||||||
Obligation at prior measurement date | $ | 84 | $ | 66 | ||||
Service cost | 1 | 1 | ||||||
Interest cost | 4 | 4 | ||||||
Actuarial losses / (gains) | 3 | 14 | ||||||
Benefits paid | (4 | ) | (3 | ) | ||||
Foreign currency impact | — | 2 | ||||||
Obligation at measurement date | $ | 88 | $ | 84 | ||||
Change in Fair Value of Plan Assets | ||||||||
Plan assets at prior measurement date | $ | — | $ | — | ||||
Benefits paid | (4 | ) | (3 | ) | ||||
Employer contributions | 4 | 3 | ||||||
Plan assets at measurement date | $ | — | $ | — | ||||
Funded status | $ | (88 | ) | $ | (84 | ) | ||
Unrecognized net experience loss | — | 23 | ||||||
Contributions between measurement date and year end | 2 | 1 | ||||||
Accrued pension liability | $ | (86 | ) | $ | (60 | ) | ||
For Westcoast, the accumulated benefit obligation was $83 million at September 30, 2006 and $82 million at September 30, 2005.
Non-Qualified Pension Plans—Amounts Recognized in the Consolidated Balance Sheets for Westcoast Consist of:— as of December 31,
| 2006 | 2005 | |||||||
| (in millions) | ||||||||
Accrued pension liability(a) | $ | (86 | ) | (81 | ) | |||
Accumulated other comprehensive income | — | 21 | ||||||
Net amount recognized | $ | (86 | ) | $ | (60 | ) | ||
| (a) | Includes approximately $6 million recognized in Other within Current Liabilities on the Consolidated Balance Sheets as of December 31, 2006. |
139
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
As a result of the adoption of SFAS No. 158, certain previously unrecognized amounts were recognized in the amounts noted above with an offset to Accumulated Other Comprehensive Income and Deferred Income Taxes as of December 31, 2006. The table below details the components of these balances.
Non-Qualified Pension Plans—Amounts Recognized Accumulated Other Comprehensive Income for Westcoast Consist of:—as of December 31, 2006
| (in millions) | ||||
Deferred income tax liability (asset) | $ | (9 | ) | |
Net actuarial loss | 25 | |||
Net amount recognized- Accumulated other comprehensive income | $ | 16 | ||
At December 31, 2006, approximately $1 million of unrecognized losses was included in Accumulated Other Comprehensive Income in the Consolidated Balance Sheets that will be recognized in net periodic non-qualified pension costs in 2007.
Additional Information:
Non-Qualified Pension Plans—Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets for Westcoast
| 2006 | 2005 | |||||
| (in millions) | ||||||
Projected benefit obligation | $ | 88 | $ | 84 | ||
Accumulated benefit obligation | 83 | 82 | ||||
Non-Qualified Pension Plans—Assumptions Used for Pension Benefits Accounting for Westcoast
| 2006 | 2005 | 2004 | ||||
| (percentages) | ||||||
Benefit Obligations | ||||||
Discount rate | 5.00 | 5.00 | 6.25 | |||
Salary increase | 3.50 | 3.25 | 3.25 | |||
Net Periodic Benefit Cost | ||||||
Discount rate | 5.00 | 6.25 | 6.00 | |||
Salary increase | 3.25 | 3.25 | 3.25 | |||
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.
Non-Qualified Plans—Expected Westcoast Benefit Payments
Years Ended December 31, | (In millions) | ||
2007 | $ | 5 | |
2008 | 5 | ||
2009 | 5 | ||
2010 | 5 | ||
2011 | 5 | ||
2012 – 2016 | 26 | ||
140
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Other Post-Retirement Benefit Plans
Duke Energy U.S. Other Post-Retirement Benefits. Spectra Energy Capital and most of its subsidiaries, in conjunction with Duke Energy, provide certain 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 is amortized over approximately 20 years. 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 plan is 13 years.
The fair value of Duke Energy’s plan assets was $237 million as of September 30, 2006 and $242 million as of September 30, 2005. The accumulated post-retirement benefit obligation was $767 million as of September 30, 2006 and $791 million as of September 30, 2005.
Spectra Energy Capital’s pre-tax net periodic post-retirement benefit cost included in continuing operations, as allocated by Duke Energy, was $9 million for 2006, 2005 and 2004, respectively. These amounts exclude pre-tax post retirement benefit cost of $10 million in each of 2006, 2005 and 2004 related to entities transferred to Duke Energy, which are reflected in Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations (see Note 1).
Westcoast 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 applies 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. Actuarial gains and losses are 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.
Other Post-Retirement Benefit Costs—Components of Net Periodic Other Post-Retirement Benefit Costs for Westcoast – for the years ended December 31,
| 2006 | 2005 | 2004 | ||||||||||
| (in millions) | ||||||||||||
Service cost benefit earned during the year | $ | 4 | $ | 3 | $ | 3 | ||||||
Interest cost on accumulated post-retirement benefit obligation | 7 | 6 | 5 | |||||||||
Amortization of prior service cost | (1 | ) | (1 | ) | (1 | ) | ||||||
Amortization of loss | 2 | 1 | 1 | |||||||||
Net periodic other post-retirement benefit costs | $ | 12 | $ | 9 | $ | 8 | ||||||
141
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Other Post-Retirement Benefits Costs—Reconciliation of Funded Status to Accrued Other Post-Retirement Benefit Costs for Westcoast —as of December 31,
| 2006 | 2005 | |||||||
| (in millions) | ||||||||
Change in Benefit Obligation | ||||||||
Accumulated post-retirement benefit obligation at prior measurement date | $ | 117 | $ | 86 | ||||
Service cost | 4 | 3 | ||||||
Interest cost | 7 | 6 | ||||||
Actuarial (gain)/loss | (34 | ) | 21 | |||||
Benefits paid | (4 | ) | (3 | ) | ||||
Foreign currency impact | 1 | 4 | ||||||
Accumulated post-retirement benefit obligation at measurement date | $ | 91 | $ | 117 | ||||
| 2006 | 2005 | |||||||
| (in millions) | ||||||||
Change in Fair Value of Plan Assets | ||||||||
Plan assets at prior measurement date | $ | — | $ | — | ||||
Benefits paid | (4 | ) | (3 | ) | ||||
Employer contributions | 4 | 3 | ||||||
Plan assets at measurement date | $ | — | $ | — | ||||
Funded status | $ | (91 | ) | $ | (117 | ) | ||
Employer contributions made after measurement date | 1 | 1 | ||||||
Unrecognized net experience loss | — | 49 | ||||||
Unrecognized prior service cost | — | (11 | ) | |||||
Accrued other post-retirement benefit costs recognized | $ | (90 | ) | $ | (78 | ) | ||
Other Post-Retirement Benefit Plans—Amounts Recognized in the Consolidated Balance Sheets for Westcoast Consist of:
| 2006 | 2005 | |||||||
| (in millions) | ||||||||
Accrued other post-retirement liability(a) | $ | (90 | ) | $ | (78 | ) | ||
Net amount recognized | $ | (90 | ) | $ | (78 | ) | ||
| (a) | Includes approximately $4 million recognized in Other within Current Liabilities on the Consolidated Balance Sheets as of December 31, 2006. |
As a result of the adoption of SFAS No. 158, certain previously unrecognized amounts were recognized in the amounts noted above with an offset to Accumulated Other Comprehensive Income and Deferred Income Taxes as of December 31, 2006. The table below details the components of these balances.
Other Post-Retirement Benefit Plans—Amounts Recognized in Accumulated Other Comprehensive Income for Westcoast Consist of:—as of December 31, 2006
| (in millions) | ||||
Deferred income tax asset | $ | (1 | ) | |
Prior Service Cost | (11 | ) | ||
Net Actuarial Loss | 14 | |||
Net amount recognized—Accumulated other comprehensive income | $ | 2 | ||
142
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Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
Other Post Retirement Benefit Plans—Amounts in Accumulated Other Comprehensive Income for Westcoast to be Recognized in Net Periodic Other Post-Retirement Benefit Costs in 2007 Consist of (in millions):
Unrecognized Prior Service Cost | $ | (1 | ) | |
Net amount to be recognized | $ | (1 | ) | |
For measurement purposes, plan assets were valued as of September 30 for Westcoast plans.
Other Post-Retirement Benefits—Assumptions Used for Other Post-Retirement Benefits Accounting for Westcoast
| (percentages) | ||||||
Determined Benefit Obligations | 2006 | 2005 | 2004 | |||
Discount rate | 5.00 | 5.00 | 6.25 | |||
Salary increase | 3.50 | 3.25 | 3.25 | |||
Determined Expense | ||||||
Discount rate | 5.00 | 6.25 | 6.00 | |||
Salary increase | 3.25 | 3.25 | 3.25 | |||
For Westcoast the discount rate used to determine the post-retirement 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
| 2006 | 2005 | |||||
Health care cost trend rate assumed for next year | 8.0 | % | 7.00 | % | ||
Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 5.00 | % | 5.00 | % | ||
Year that the rate reaches the ultimate trend rate | 2010 | 2008 |
Sensitivity to Changes in Assumed Health Care Cost Trend Rates Westcoast Plans(millions)
1-Percentage- Point Increase | 1-Percentage- Point Decrease | ||||||
Effect on total service and interest costs | $ | 2 | $ | (1 | ) | ||
Effect on post-retirement benefit obligation | 6 | (5 | ) | ||||
Westcoast expects to make the future benefit payments, which reflect expected future service, as appropriate. Duke Energy expects to receive future subsidies under Medicare Part D. The following benefit payments and subsidies are expected to be paid (or received) over each of the next five years and thereafter.
Other Post-Retirement Plans—Expected Benefit Payments (in millions)
| Westcoast Plans | |||
2007 | $ | 4 | |
2008 | 4 | ||
2009 | 4 | ||
2010 | 4 | ||
2011 | 4 | ||
2012 – 2016 | 23 | ||
143
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
20. Other Income and Expenses, net
The components of Other Income and Expenses, net on the Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004 are as follows:
| For the years ended December 31, | |||||||||||
| 2006 | 2005 | 2004 | |||||||||
| (in millions) | |||||||||||
Income/(Expense) | |||||||||||
Interest income | $ | 32 | $ | 41 | $ | 37 | |||||
Foreign exchange gains (losses) | — | (4 | ) | 12 | |||||||
AFUDC allowance | 11 | 8 | 9 | ||||||||
Realized and unrealized mark-to-market impact on discontinued hedges | (19 | ) | (64 | ) | — | ||||||
Other(a) | 91 | 87 | 163 | ||||||||
Total | $ | 115 | $ | 68 | $ | 221 | |||||
| (a) | Primarily represents a management fee charged by Spectra Energy Capital to an unconsolidated affiliate (see Note 10) |
21. Subsequent Events
The spin-off of the natural gas businesses by Duke Energy was effective January 2, 2007. The new natural gas company, which is named Spectra Energy, principally consists of Spectra Energy Capital and its Natural Gas Transmission and Field Services business segments. Assets and liabilities of entities included in the spin-off of Spectra Energy were transferred from Duke Energy on a historical cost basis on the date of the spin-off transaction. As a result of the spin-off, all of the limited liability interests of Spectra Energy Capital were contributed by Duke Energy to Spectra Energy.
On March 30, 2007, a subsidiary of Spectra Energy Capital filed a Form S-1 with the SEC to register limited partner units of a proposed master limited partnership that would hold certain pipeline and storage assets of Spectra Energy Capital. The assets include a 100% interest in East Tennessee, a 50% interest in the Moss Bluff and Egan storage assets owned through Market Hub Partners, a wholly-owned subsidiary of Spectra Energy Capital, and approximately one-half (24.5%) of Spectra Energy Capital’s 50% ownership interest in Gulfstream.
For information on other subsequent events, see Notes 1, 4, 16, 19 and 23.
22. Quarterly Financial Data (Unaudited)
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Total | ||||||||||||
| (in millions) | ||||||||||||||||
2006(a) | ||||||||||||||||
Operating revenues | $ | 1,485 | $ | 981 | $ | 869 | $ | 1,197 | $ | 4,532 | ||||||
Operating income | 385 | 322 | 252 | 286 | 1,245 | |||||||||||
Net income | 222 | 320 | 447 | 255 | 1,244 | |||||||||||
2005(a) | ||||||||||||||||
Operating revenues | $ | 3,717 | $ | 3,594 | $ | 900 | $ | 1,243 | $ | 9,454 | ||||||
Operating income | 345 | 454 | 845 | 209 | 1,853 | |||||||||||
Net income (loss) | 652 | 129 | (534 | ) | 427 | 674 | ||||||||||
| (a) | Operating revenues and operating income for quarterly periods in 2006 and 2005 have changed from prior filings as a result of the classification of certain operations from continuing operations to discontinued operations for all periods presented (see Note 1). |
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SPECTRA ENERGY CAPITAL, LLC
(formerly Duke Capital LLC)
Notes to Consolidated Financial Statements — Continued
During the first quarter of 2006, Spectra Energy Capital recorded the following unusual or infrequently occurring item: an approximate $24 million pre-tax gain on the settlement of a customer’s transportation contract (see Note 2).
During the second quarter of 2006, Spectra Energy Capital recorded the following unusual or infrequently occurring items: an approximate $55 million pre-tax other-than-temporary impairment charge related to International Energy’s investment in Campeche, which is included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations (see Note 12).
During the third quarter of 2006, Spectra Energy Capital recorded the following unusual or infrequently occurring items: an approximate $250 million pre-tax gain on the sale of an effective 50% interest in the Crescent JV (see Note 12); and an approximate $38 million additional gain on the sale of DENA’s assets to LS Power as a result of LS Power obtaining certain regulatory approvals (see Note 12). Both of these gains are included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.
During the fourth quarter of 2006, Spectra Energy Capital recorded the following unusual or infrequently occurring items: an approximate $100 million pre-tax charge to establish a settlement reserve related to the Citrus litigation (see Note 16); and an approximate $28 million pre-tax impairment charge at International Energy as a result of the pending sale of operations in Bolivia, which is included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations (see Note 12).
During the first quarter of 2005, Spectra Energy Capital recorded the following unusual or infrequently occurring items: an approximate $0.9 billion (net of minority interest of approximately $0.3 billion) pre-tax gain on sale of DCP Midstream’s wholly-owned subsidiary, TEPPCO GP (see Note 2); an approximate $100 million pre-tax gain on sale of Spectra Energy Capital’s limited partner interest in TEPPCO LP (see Note 2); an approximate $21 million pre-tax gain on sale of DENA’s partially completed Grays Harbor power plant in Washington State, which is included in Loss (Income) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations (see Note 12); and an approximate $230 million of unrealized pre-tax losses on certain 2005 and 2006 derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the anticipated deconsolidation of DCP Midstream by Spectra Energy Capital (see Note 2).
During the third quarter of 2005, Spectra Energy Capital recorded the following unusual or infrequently occurring items: an approximate $1.3 billion pre-tax charge for the impairment of assets and the discontinuance of hedge accounting for certain positions at DENA, as a result of the decision to exit substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern Assets, which is included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations (see Note 12); an approximate $575 million pre-tax gain associated with the transfer of 19.7% of Spectra Energy Capital’s interest in DCP Midstream to ConocoPhillips, Spectra Energy Capital’s co-equity owner in DCP Midstream, which reduced Spectra Energy Capital’s ownership interest in DCP Midstream from 69.7% to 50% (see Note 2); an approximate $105 million of unrealized and realized pre-tax losses on certain 2005 and 2006 derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the deconsolidation of DCP Midstream by Spectra Energy Capital (see Note 2); and approximately $90 million of gains at Crescent due primarily to income related to a distribution from an interest in a portfolio of office buildings and a large land sale, which is included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations (see Note 12).
During the fourth quarter of 2005, Spectra Energy Capital recorded the following unusual or infrequently occurring items: pre-tax gain of approximately $380 million, which reverses a portion of the third quarter DENA impairment, attributable to the planned asset sales to LS Power; and pre-tax losses of approximately $475 million for portfolio exit costs including severance, retention and other transaction costs at DENA, which is included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations (see Note 12).
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SPECTRA ENERGY CAPITAL LLC
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
| Additions: | |||||||||||||||
Balance at Beginning of Period | Charged to Expense | Charged to Other Accounts | Deductions(a) | Balance at End of Period | |||||||||||
| (In millions) | |||||||||||||||
December 31, 2006: | |||||||||||||||
Allowance for doubtful accounts | $ | 121 | $ | 23 | $ | 14 | $ | 145 | $ | 13 | |||||
Other(b) | 708 | 226 | 67 | 765 | 236 | ||||||||||
| $ | 829 | $ | 249 | $ | 81 | $ | 910 | $ | 249 | ||||||
December 31, 2005: | |||||||||||||||
Allowance for doubtful accounts | $ | 128 | $ | 21 | $ | 10 | $ | 38 | $ | 121 | |||||
Other(b) | 710 | 330 | 64 | 396 | 708 | ||||||||||
| $ | 838 | $ | 351 | $ | 74 | $ | 434 | $ | 829 | ||||||
December 31, 2004: | |||||||||||||||
Allowance for doubtful accounts | $ | 272 | $ | 66 | $ | 3 | $ | 213 | $ | 128 | |||||
Other(b) | 978 | 228 | 95 | 591 | 710 | ||||||||||
| $ | 1,250 | $ | 294 | $ | 98 | $ | 804 | $ | 838 | ||||||
| (a) | Principally cash payments and reserve reversals. Also includes transfer of certain operations to Duke Energy in April 2006 and December 2006 as discussed in Note 1. |
| (b) | Principally insurance related reserves at Bison, litigation and other reserves, included in Other Current Liabilities, or Deferred Credits and Other Liabilities on the Consolidated Balance Sheets. |
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Disclosure Controls and Procedures
Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by Spectra Energy in the reports it files or submits under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized, and reported, within the time periods specified by the Securities and Exchange Commission’s (SEC) rules and forms.
Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by Spectra Energy in the reports it files or submits under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, Spectra Energy has evaluated the effectiveness of its disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2006, and, based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance that information requiring disclosure is recorded, processed, summarized, and reported within the timeframe specified by the SEC’s rules and forms.
Changes in Internal Control over Financial Reporting
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, Spectra Energy has evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended December 31, 2006 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting, other than the changes occurring in preparation for the spin-off of Spectra Energy from Duke Energy on January 2, 2007, as discussed below. The preparation of this Form 10-K report was conducted using existing financial systems and disclosure controls of Duke Energy under the supervision and participation of the Chief Executive Officer and Chief Financial Officer of Spectra Energy.
In preparation for the spin-off, Spectra Energy has been in the process of creating new corporate functions, including those that affect internal control over financial reporting. Spectra Energy is also relying on Duke Energy during 2007 for financial system processing support and other services primarily around information systems and human resource and employee benefit functions. During 2007, as part of its analysis of internal control over financial reporting, Spectra Energy will maintain internal control over corporate and other functions created as a result of the spin-off of Spectra Energy and will, to the extent necessary, evaluate Duke Energy processes that impact Spectra Energy’s internal control over financial reporting. See Note 21 to the Consolidated Financial Statements for additional information related to the spin-off of Spectra Energy from Duke Energy.
This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the company’s registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.
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PART III
ITEM 10. Directors, Executive Officers and Corporate Governance
Reference to “Executive Officers of Spectra Energy” is included in “Item 1. Business” of this report.
Board of Directors
In addition to Mr. Fowler and Ms. Wyrsch whose information is included in Item 1 of this report, the following sets forth information with respect to the Board of Directors of Spectra Energy. There are no arrangements between any director and any other person pursuant to which such director was selected for nomination.
Name | Age | Position(s) | ||
Paul M. Anderson | 61 | Chairman of the Board of Directors | ||
Roger Agnelli | 47 | Director | ||
William T. Esrey | 66 | Director | ||
Dennis R. Hendrix | 66 | Director | ||
Michael E.J. Phelps | 59 | Director | ||
Austin A. Adams | 64 | Director | ||
Peter B. Hamilton | 60 | Director |
Paul M. Anderson served as Chairman of the Board of Duke Energy from April 2006 until assuming his current position upon the separation of Spectra Energy from Duke Energy. From November 2003 until the merger of Duke Energy and Cinergy Corp. in April 2006, Mr. Anderson served as Chairman of the Board and Chief Executive Officer of Duke Energy. Prior to such time, Mr. Anderson served as Managing Director and Chief Executive Officer of BHP Billiton Ltd and BHP Billiton PLC, which operate on a combined basis as BHP Billiton, the world’s largest diversified resources company and which is involved in major commodity businesses, from 1998 until his retirement in July 2002. Mr. Anderson also served on the Board of Directors of Fluor Corporation from March 2003 until October 2003, the Board of Directors of Temple Inland Inc. from August 2002 to May 2004, the Board of Directors of Qantas Airways from September 2002 to the present, and the Board of Directors of BHP Billiton Limited from June 2006 to the present. Prior to joining BHP in 1998, Mr. Anderson had a career that spanned more than 20 years at Duke Energy and its predecessor companies, including serving as Chief Executive Officer of PanEnergy Corp. Mr. Anderson is currently a director of Quantas Airways Limited, BHP Billiton Limited and BHP Billiton Plc.
Roger Agnelli is currently President and Chief Executive Officer of CVRD, a global mining company and the world’s largest producer of iron ore. Mr. Agnelli was elected to that position in 2001. He served in various positions at Bradesco, a Brazilian financial conglomerate, from 1981 to 2001 and was President and CEO of Bradespar S.A. from March 2000, to July 2001. He is a director of Asea Brown Boveri (ABB Ltd), Suzano Petroquímica S.A. and Petrobras-Petroleo Brasileiro S.A.
William T. Esrey is Chairman Emeritus of Sprint Corporation, a diversified telecommunications holding company, since 2003. Prior to that he served as its Chief Executive Officer from 1985 to 2003, and as its Chairman from 1990 to 2003. He also served as Chairman of Japan Telecom from 2003 to 2004. Mr. Esrey is a director of General Mills, Inc.
Dennis R. Hendrix is currently the retired Chairman of the Board of PanEnergy Corp. He was Chairman of the Board of PanEnergy Corp from 1990 to 1997, Chief Executive Officer from 1990 to 1995 and President from 1990 to 1993. From 1997 to 2002 and from 2004 to the present Mr. Hendrix served as a director of Duke Energy. From 2002 until 2004 Mr. Hendrix served on the boards of Allied Waste Industries and Newfield Exploration Company, including serving as lead director of Allied Waste since December 2002, as well as Grant Prideco, Inc.
Mr. Michael E.J. Phelps is Chairman of Dornoch Capital Inc., a private investment company. In 2003, the Canadian government appointed Mr. Phelps as Chairman of “the Wise Persons’ Committee,” a panel developed to review Canada’s system of securities regulation. From January 1988 to 2002, he served as President and Chief
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Executive Officer, and subsequently as Chairman and Chief Executive Officer, of Westcoast Energy Inc., Vancouver, BC. In 2001, Mr. Phelps was appointed as an Officer to the Order of Canada. Mr. Phelps sits on the Board of Directors of Canadian Pacific Railway Company, Canfor Corporation, Spectra Energy Corp. (separated from Duke Energy Corp. January 2007), Fairborne Energy Trust and the Vancouver Organizing Committee for 2010 Olympic and Paralympic Games. He is currently Chairman of the Board of the GLOBE Foundation of Canada and Kodiak Exploration Limited. From 1997 to 2006 he served as Chairman of the Committee to Nominate the Canada Pension Plan Investment Board. Mr. Phelps also serves on the board of the VGH & UBC Hospital Foundation. Mr. Phelps is a Senior Advisor to Deutsche Bank AG, Canada and a Special Advisor to CVRD Inco.
Austin Adams is the former chief information officer of JPMorgan Chase, the third largest bank holding company in the world. He assumed that role upon the merger of JPMorgan Chase and Bank One Corporation in 2004. Before joining Bank One in 2001, Mr. Adams served as Chief Information Officer at First Union Corporation, now Wachovia Corp. He is currently a director of NCO Group.
Peter Hamilton is currently the retired vice chairman and president of Brunswick Corporations’ Boat Division. He has served in a number of executive leadership capacities for Brunswick, including chief financial officer, a role he also held for Cummins, Inc. Mr. Hamilton has served in a number of distinguished government positions, including special assistant to the secretary and deputy secretary, Department of Defense; executive assistant to the secretary, Department of Health, Education and Welfare; deputy general counsel, Department of Health, Education and Welfare; and general counsel, Department of the U.S. Air Force.
Class of Directors
Spectra Energy’s certificate of incorporation and by-laws divide Spectra Energy’s board of directors into three classes with staggered terms, which means that the directors in one of these classes will be elected each year for a new three-year term. Class I directors have an initial term expiring in 2007, Class II directors have an initial term expiring in 2008, and Class III directors have an initial term expiring in 2009. Class I is comprised of Messrs. Fowler, Esrey and Hendrix, Class II is comprised of Messrs. Anderson, Adams and Agnelli, and Class III is comprised of Ms. Wyrsch and Messrs. Hamilton and Phelps.
Audit Committee
The members of the Audit Committee of the Board of Directors of Spectra Energy are Messrs. Esrey, Adams, Hamilton and Hendrix. Each of these members has been determined to be “independent” within the meaning of Sections 303A.02, 303A.06 and 303A.07 of the NYSE’s listing standards and Rule 10A-3 of the Securities Exchange Act of 1934 and the company’s categorical standards for independence. In addition, each of these members meet the expertise requirements for audit committee membership under the NYSE’s rules and the rules and regulations of the SEC. The Board has determined that Mr. Esrey and Mr. Hamilton are “audit committee financial experts” as such term is defined in Item 401(h) of Regulation S-K.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires Spectra Energy’s directors and executive officers, and any persons owning more than ten percent of Spectra Energy’s common stock, to file with the SEC initial reports of beneficial ownership and certain changes in that beneficial ownership, with respect to the equity securities of Duke Energy. Spectra Energy prepares and files these reports on behalf of its directors and executive officers. To Spectra Energy’s knowledge, all Section 16(a) reporting requirements applicable to its directors and executive officers were complied with during 2006.
Code of Ethics
Spectra Energy has adopted a Code of Business Ethics that applies to all employees including our executive officers. All of our Board committee charters, as well as our Principles for Corporate Governance, Code of Business Ethics and Code of Business Conduct & Ethics for the directors are available on our website atwww.spectraenergy.com/investors/governance and are available in print upon request. Any amendment to or waiver from our Code of Business Ethics for executive officers or Code of Business Conduct & Ethics for directors must be approved by the Board and will be posted on our website.
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Item 11. Executive Compensation
Report of the Compensation Committee
The Compensation Committee of Spectra Energy has reviewed and discussed the following Compensation Discussion and Analysis with management and, based on such review and discussions, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in the Spectra Energy 2006 Form 10-K.
Compensation Committee
Michael E. J. Phelps (Chair)
Austin A. Adams
Roger Agnelli
Peter B. Hamilton
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Compensation Discussion and Analysis
The purpose of this Compensation Discussion and Analysis is to provide information about Spectra Energy’s objectives and policies regarding future compensation for the officers of Spectra Energy listed in the Summary Compensation Table, who are referred to as the named executive officers. Prior to the spin-off of Spectra Energy to the shareholders of Duke Energy on January 2, 2007, Spectra Energy was a wholly-owned subsidiary of Duke Energy and its executive officers were employees of Duke Energy. Accordingly, during 2006 the employees of Duke Energy who later assumed positions as Spectra Energy’s executive officers once Spectra Energy became a stand-alone publicly-traded entity were compensated in accordance with the compensation policies of Duke Energy and the Compensation Committee of the Board of Directors of Duke Energy was responsible for making the compensation decisions for the Spectra Energy named executive officers. Accordingly, this Compensation Discussion and Analysis also provides context for the numbers and narrative description regarding 2006 compensation from Duke Energy to these individuals as set out under “Executive Compensation” below.
On December 19, 2006, the Compensation Committee of the Spectra Energy Board of Directors was named to take responsibility for establishing the compensation of Spectra Energy’s executive officers. The Spectra Energy Compensation Committee met on December 19, 2006 and to date has met twice in 2007. At its December 2006 meeting, prior to Spectra Energy becoming a stand-alone public entity, the Spectra Energy Compensation Committee reviewed and approved the initial framework of executive compensation that was established by Duke Energy.
Committee Overview
The Spectra Energy Compensation Committee is comprised of non-employee directors, each of whom is considered to be (1) “independent” under the currently applicable listing standards of the New York Stock Exchange; (2) a “non-employee director” within the meaning of Rule 16b-3 under the Securities and Exchange Act of 1934; and, but for the exception described below, (3) an “outside director” within the meaning of Section 162(m) of the Internal Revenue Code of 1986, as amended. Committee members include Mr. Michael E. J. Phelps (Chair), Mr. Austin A. Adams, Mr. Roger Agnelli and Mr. Peter B. Hamilton. Mr. Phelps was not considered to be an “outside director” prior to March 14, 2007 due to his prior position as the officer of an affiliate of Westcoast Energy, Inc. Since that time he has met the requirements of an “outside director” within the meaning of Section 162(m) of the Internal Revenue Code of 1986, as amended.
The Spectra Energy Compensation Committee operates under a written charter adopted by the Board of Directors. The charter is available to view at www.spectraenergy.com/investors/governance. The fundamental responsibilities of the Spectra Energy Compensation Committee are to: (1) review and approve the overall compensation philosophy of Spectra Energy as it applies to the initial compensation of executives of Spectra Energy; (2) review and approve the annual salary, short-term incentive opportunities, long-term incentive opportunities, and other benefits of the Chief Executive Officer and other executive officers; (3) review and approve any employment or severance agreement entered into with an executive officer; (4) approve equity grants under Spectra Energy’s long-term incentive plan; (5) review the effectiveness of Spectra Energy’s compensation program in obtaining desired results and approve any changes thereto; (6) approve changes to Spectra Energy’s compensation program; and (7) review and recommend to the full Spectra Energy Board the compensation of non-employee directors.
Committee Meetings
It is expected that the Spectra Energy Compensation Committee will meet as often as is necessary to perform its duties and responsibilities. The Spectra Energy Compensation Committee’s Chair works with management to establish the meeting agenda. The Spectra Energy Compensation Committee receives and reviews materials in advance of each meeting. These materials include information that management believes will be helpful to the Spectra Energy Compensation Committee as well as materials the Spectra Energy Compensation Committee has specifically requested. It is expected that (depending on the agenda for a particular meeting) these materials may include such things as information relating to (1) the competitiveness of executive and/or director compensation programs based on market data; (2) the total compensation provided to executives; (3) trends in executive compensation and/or benefits; (4) executive and director stock ownership levels; and (5) corporate and individual performance compared to predetermined objectives.
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The Spectra Energy Compensation Committee met on December 19, 2006 to approve: (1) preliminary compensation matters in connection with the spin-off and (2) executive change in control agreements for officers. The Committee has met twice during the first quarter of the 2007 fiscal year and took the following actions: (1) approved Spectra’s Long-Term Incentive Grant Date Policy; (2) approved the delegation of authority for Long-Term Incentive Grants to the Chief Executive Officer for those employees not explicitly under the purview of the Spectra Energy Compensation Committee; (3) made recommendations to the Board regarding compensation for Spectra Energy’s Chairman; (4) appointed Mssrs. Adams, Agnelli and Hamilton as members of the Spectra Energy Compensation Committee’s Performance-Based Subcommittee; (5) approved Spectra Energy’s Stock Ownership Policy for those employees who participate in Spectra Energy’s Long-Term Incentive program and receive annual grants; and (6) reviewed and discussed this Compensation Discussion and Analysis. The Spectra Energy Compensation Committee’s Performance-Based Subcommittee (1) approved Revised 2007 Short-Term Incentive Plan targets, guidelines and objectives for certain of Spectra Energy’s executives; (2) approved Spectra Energy’s Long-Term Incentive Plan grants for 2007; and (3) approved bonuses for certain Spectra Energy employees related to the spin-off of Spectra Energy. Mr. Phelps recused himself from these decisions made by the Spectra Energy Compensation Committee’s Performance-Based Subcommittee.
Committee Advisors
The Spectra Energy Compensation Committee Charter grants the Spectra Energy Compensation Committee authority to engage advisors and compensation consultants. In this regard, the Spectra Energy Compensation Committee intends to engage an independent consulting firm to report directly to the Spectra Energy Compensation Committee with respect to matters related to executive compensation and best practices and analysis of meeting materials prepared by management. The Spectra Energy Compensation Committee is currently evaluating a number of candidates for this position and expects to appoint such a consultant during 2007. The Duke Energy Compensation Committee engaged an outside consultant to advise it on matters related to compensation, including the 2006 compensation of its employees who became the Spectra Energy named executive officers.
Management’s Role in the Compensation-Setting Process
Members of Spectra Energy’s management participated in various aspects of the compensation-setting process for 2007 including (1) recommending compensation programs, compensation policies, compensation levels and incentive opportunities; (2) compiling, preparing and distributing materials for Spectra Energy Compensation Committee meetings, including market data; (3) recommending performance targets and objectives; and (4) assisting in the evaluation of employee performance. Spectra Energy expects that its management will continue to be involved in the compensation-setting process. In addition, Spectra Energy anticipates that management will review the performance of each executive within the purview of the Spectra Energy Compensation Committee (other than the Chief Executive Officer whose performance will be reviewed by the Corporate Governance Committee).
Compensation Program
Objectives of the Compensation Program
Historically, Duke Energy linked compensation to performance with significant upside and downside potential depending upon actual results as compared to predetermined measures of success. Consistent with that policy, more than half of the compensation opportunity provided to the Duke Energy employees who became Spectra Energy’s named executive officers was provided in the form of short-term and long-term incentives, which yielded varying levels of compensation and associated costs depending on the extent that predetermined corporate, business unit and individual goals were achieved in 2006. A significant portion of such compensation was awarded under Duke Energy’s short-term incentive plan. As discussed below, payments under such plan were determined by Duke Energy in March of 2007 and were paid by Spectra Energy in accordance with a spin-off related agreement between Duke Energy and Spectra Energy covering employee matters.
During 2007, the Spectra Energy Compensation Committee intends to conduct a detailed review of past Duke Energy compensation philosophies in connection with establishing the compensation philosophy of Spectra Energy for future periods. Any changes to such philosophies will be reflected in the compensation packages of Spectra Energy’s executives for 2008.
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Setting Executive Compensation Consistent with Duke Energy’s Compensation Philosophy
Consistent with its past compensation philosophy, the Duke Energy Compensation Committee established Spectra Energy named executive officers at a level that approximated the median salaries of individuals in comparable positions and markets and established short-term incentive opportunities intended to provide total cash compensation at the market median for individuals in comparable positions and markets in the event of the achievement of target performance and above market median in the event of outstanding financial, operational and individual results. In accordance with the goals of the Duke Energy executive compensation standards, equity-based compensation (i.e., long-term incentive compensation) constituted more than 50% of the 2006 incentive opportunity for these individuals.
For 2007, total direct compensation opportunities, comprised of base salary, annual incentive targets and the value of annual long-term incentive awards for Spectra Energy named executive officers that became effective upon the spin-off were reviewed and approved by the Duke Energy Compensation Committee prior to the spin-off of Spectra Energy when Duke Energy was the sole shareholder of the entity that became Spectra Energy. Duke Energy applied its compensation philosophy in determining the compensation for each of Spectra Energy’s named executive officers for 2007. The Spectra Energy Compensation Committee reviewed and approved the compensation for the Spectra Energy named executive officers at its December 19, 2006 meeting.
Elements of the Compensation Plan
As discussed in more detail below, during 2006 the principal components of compensation for the Spectra Energy named executive officers were:
| • | base salary; |
| • | short-term incentive compensation; |
| • | long-term equity incentive compensation; |
| • | retirement and other benefits; and |
| • | severance. |
Base Salary. Base salaries for the Spectra Energy named executive officers were determined by the Duke Energy Compensation Committee based upon job responsibilities, level of experience, individual performance, and comparisons to the salaries of executives or employees in similar positions obtained from market surveys and internal comparisons. The Duke Energy Compensation Committee established all salary adjustments for its officers for 2007 including the salaries of the employees who would be appointed Spectra Energy’s named executive officers effective upon the spin-off. These salaries were reviewed and approved by the Spectra Energy Compensation Committee at its December 19, 2006 meeting.
Short-Term Incentives. For 2006, short-term incentive opportunities were provided to employees of Duke Energy who became Spectra Energy’s named executive officers under the Duke Energy Corporation Executive Short-Term Incentive Plan (“STI Plan”). The threshold, target and maximum incentive opportunities for each participant in the Duke STI Plan were based on a percentage of his or her base salary, along with the individual, corporate and/or business unit goals whose achievement was required to earn those incentive opportunities. For more details regarding target incentive opportunities, please see “Executive Compensation – Non Equity Incentive Compensation.”
During 2006, 80% of this opportunity was based on achievement of corporate and/or business unit financial goals at Duke Energy, and the remaining 20% was based on achievement of individual goals. The primary 2006 corporate goal consisted of a pre-established on-going earnings per share goal. In addition, Duke Energy included a safety penalty in the 2006 short-term incentive program in order to encourage a continued focus on safety. In particular, in the event of a fatality of any Duke Energy employee, contractor or sub-contractor during 2006, the short-term incentive opportunity of each executive who participated in Duke Energy’s long-term incentive program during 2006 would be reduced by 5%.
Payments for 2006 awards to Spectra Energy executives under the STI Plan were calculated by Duke Energy in March 2007 based on evaluations of 2006 performance and were paid by Spectra Energy.
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For 2007, each Spectra Energy executive officer, including all of the named executive officers, will participate in the Spectra Energy Executive Short-Term Incentive (STI) Plan. Eighty percent of STI incentives for Messrs. Fowler and Ebel will be determined by financial objectives including Spectra Energy earnings per share, Spectra Energy Transmission earnings before interest, taxes, depreciation and amortization, or EBITDA, Spectra Energy Transmission return on capital employed and measures related to the financial performance of DCP Midstream. Eighty percent of STI incentives for Ms. Wyrsch and Messrs. Harris and Garner will be based on corporate financial objectives including Spectra Energy earnings per share, Spectra Energy Transmission EBITDA and Spectra Energy Transmission return on capital employed. Twenty percent of all executive officers’ 2007 STI is determined by performance on individual goals.
The Duke Energy Compensation Committee approved, and the Spectra Energy Compensation Committee subsequently reviewed and approved, bonus targets for each of Spectra Energy’s named executive officers. Bonus targets are expressed as a percentage of base annual salary and may be earned based upon the financial, operational and individual measures described above. Up to 200% of the bonus amount contingent upon any financial or operational measure may be paid if performance at a specified maximum level is achieved. The maximum that may be earned for performance on individual measures is 150% of target. The amount that may be paid for performance at a specified minimum level is 50% of the target amount. Target bonuses expressed as a percentage of base annual salary for Spectra Energy named executive officers in 2007 as approved by the Duke Energy Compensation Committee and subsequently reviewed and approved by the Spectra Energy Compensation Committee are:
Name | Percentage of Salary | ||
Fred J. Fowler | 90 | % | |
Gregory L. Ebel | 65 | % | |
Martha B. Wyrsch | 80 | % | |
Alan N. Harris | 50 | % | |
William S. Garner, Jr. | 50 | % |
Long-Term Incentives. Duke Energy has historically provided long-term incentive opportunities to its executive officers to align executive and shareholder interests in an effort to maximize shareholder value. One-half of each Spectra Energy named executive officer’s 2006 long-term incentive opportunity was provided by Duke Energy in the form of Duke Energy phantom shares and the remaining half was provided in the form of Duke Energy performance shares, as follows:
Name | Grant Date | Performance Shares (at Target Level) | Phantom Shares | |||
Fred J. Fowler | 4/4/2006 | 36,640 | 36,640 | |||
Gregory L. Ebel | 4/4/2006 | 3,553 | 3,550 | |||
Martha B. Wyrsch | 4/4/2006 | 15,540 | 15,540 | |||
Alan N. Harris | 4/4/2006 | 5,113 | 5,110 | |||
William S. Garner, Jr. | 5/10/2006 | 3,073 | 3,070 |
Upon vesting, the holder of performance shares or phantom shares receive shares of the underlying common stock. Phantom shares typically vest upon continued employment for a specified period of time, while performance shares typically vest upon the achievement of specified corporate performance measures. The Duke Energy phantom shares granted in 2006 generally vest in equal portions on each of the first five anniversaries of the grant date, provided the recipient continues to be employed by Spectra Energy or his or her employment terminates due to retirement. The Duke Energy performance shares granted in 2006 generally vest only to the extent that certain total shareholder return (“TSR”) targets for the three-year period from January 1, 2006 to December 31, 2008 are met as compared with the TSR of a peer group of companies. Please see “Executive Compensation—Long-Term Incentive Awards Granted in 2006” for a discussion of those targets. As described in more detail under “Corporate Transactions” below, Spectra Energy performance shares and phantom shares were granted to the holders of Duke Energy performance shares and phantom shares upon the spin-off of Spectra Energy. In connection with the spin-off, adjustments were made to the TSR return requirements to take into account the share performance of both Duke Energy and Spectra Energy in calculating the extent that performance shares vest.
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In 2004, Duke Energy granted performance shares and phantom shares to certain of its employees, including certain employees who became executive officers of Spectra Energy. The phantom shares provided for vesting in equal parts over the first five anniversaries of the grant date and provided for accelerated vesting of any remaining unvested phantom shares (or a prorated portion thereof for retired participants) in the event Duke Energy’s TSR for the 2004-2006 period as compared with the TSR of the S&P 500 was at or above the 70th percentile. Duke Energy achieved a relative TSR percentile ranking of 75.6 for the 2004-2006 period, which corresponded to (i) a payout of 114.0% of the target level of performance shares and (ii) accelerated vesting of the phantom shares granted in 2004.
As discussed in more detail under “Corporate Transactions”, the terms of all outstanding Duke Energy phantom share and performance share awards were adjusted upon the spin-off of Spectra Energy by splitting the outstanding equity awards into Duke Energy and Spectra Energy equity awards. The following table lists the performance shares and phantom shares granted in 2004 in which the Spectra Energy named executive officers became vested in 2006, as adjusted for the spin-off on January 2, 2007. Mr. Garner did not receive an award, as he was not employed at the time the grants were made.
Name | Performance Shares | Phantom Shares | ||||||||
| Duke | Spectra | Duke | Spectra | |||||||
Fred J. Fowler | 64,250 | 32,125 | 33,816 | 16,908 | ||||||
Gregory L. Ebel | 4,004 | 2,002 | 2,106 | 1,053 | ||||||
Martha B. Wyrsch | 24,013 | 12,006 | 12,636 | 6,318 | ||||||
Alan N. Harris | 6,256 | 3,128 | 3,294 | 1,647 | ||||||
With respect to the 2007 long-term incentive compensation program, the Spectra Energy Compensation Committee, using analyses prepared at Duke Energy’s request by an outside compensation consultant, studied the structure of awards made to executives of companies in connection with and immediately following the time they were spun-off from a larger parent corporation. The Spectra Energy Compensation Committee also considered the long-term incentive grant structures of other midstream natural gas companies as well the prevailing grant practices among companies comparable to Spectra Energy’s size. The grant structures and practices reviewed by the Spectra Energy Compensation Committee were generally designed to compensate both continued employment and performance. In carrying out its responsibilities to assure that Spectra Energy’s management team be retained and its desire to use the long-tem incentive program to reward increases in value to investors, the Spectra Energy Compensation Committee, based on the foregoing information and analyses, determined that the most appropriate structure for long-term incentive awards to its executive officers in 2007 would be one in which: (1) one-half of intended grant value is delivered in stock options with an exercise price set at the market price of Spectra Energy as of the date of grant, and (2) one-half of the intended grant value is delivered in phantom shares that will vest in their entirety on the third anniversary of the date of grant. Stock options granted in 2007 will vest ratably over a three-year period and will have a ten year term. Dividend equivalents will accumulate on phantom shares granted in 2007 but will not be paid until the end of the three-year vesting period.
Based upon its review of the market data described above, the Spectra Energy Compensation Committee approved grant values deemed to approximate market median grant practices, resulting in 2007 awards to Spectra’ Energy’s named executive officers with values expressed as a percentage of base annual salary as shown below:
Name | Percentage of Base Salary | ||
Fred J. Fowler | 220 | % | |
Gregory L. Ebel | 140 | % | |
Martha B. Wyrsch | 200 | % | |
Alan N. Harris | 120 | % | |
William S. Garner, Jr. | 120 | % |
In calculating the number of stock options granted in accordance with the above, options were valued using an expected value model calculated at management’s request by an independent compensation consultant.
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As described in more detail below, Spectra Energy has established a stock ownership policy to complement its long-term incentive program. The ownership policy applies to all executives who participate in the long-term incentive program and all members of the Spectra Energy Board of Directors.
Retirement and Other Benefits. In 2006, Duke Energy provided employee benefits to its employees who became Spectra Energy’s named executive officers under several different plans. Based on market surveys, Duke Energy determined that these benefits were comparable to the benefits provided by peers of Duke Energy and provided an important tool for the attraction and retention of employees. In addition, Duke Energy provided the named executive officers with the same health and welfare benefits as it provides to all other similarly-situated employees, at the same cost charged to all other eligible employees.
In connection with the spin-off of Spectra Energy to the shareholders of Duke Energy, benefit programs were established for employees of Spectra Energy with provisions that are essentially the same as the provisions of programs that were in effect in 2006 for Duke Energy employees. On December 19, 2006, the Spectra Energy Compensation Committee reviewed and approved the Spectra Energy Retirement Savings Plan, the Spectra Energy Executive Savings Plan, the Spectra Energy Retirement Cash Balance Plan and the Spectra Energy Executive Cash Balance Plan to continue the benefit accrual opportunities previously available at Duke Energy under similar plans that are described below. In connection with the spin off transaction, assets and liabilities associated with the predecessor Duke Energy plans were transferred to Spectra Energy and its plans.
The Duke Energy Retirement Savings Plan, a “401(k) plan,” was generally available to all employees in the United States. The plan is a tax-qualified retirement plan that provides a means for employees to save for retirement on a tax-deferred basis and to receive an employer matching contribution. Earnings on amounts credited to the Duke Energy Retirement Savings Plan are determined by reference to investment options (including a common stock fund) selected by each participant.
The Duke Energy Executive Savings Plan was offered to a select group of management, including the Spectra Energy named executive officers, other than Mr. Ebel, who was based in Canada until January 1, 2007 and was eligible to participate in a similar Canadian plan. Mr. Ebel has participated in U.S. plans in periods prior to 2006 and currently resides in the U.S. and is eligible to participate in Spectra Energy’s U.S. plans. The plan enables these employees to defer compensation, and receive employer matching contributions, in excess of the limits of the Internal Revenue Code of 1986, as amended, that apply to qualified retirement plans such as the Duke Energy Retirement Savings Plan. Earnings on amounts credited to the Duke Energy Executive Savings Plan are determined by reference to investment options similar to those offered under the Duke Energy Retirement Savings Plan.
The Duke Energy Retirement Cash Balance Plan was generally available to all employees in the United States. It provides a defined benefit for retirement, the amount of which is based on a participant’s cash balance account balance, which grows with monthly pay and interest credits.
The Duke Energy Executive Cash Balance Plan was offered to a select group of management, including the named executive officers, other than Mr. Ebel, who was based in Canada until January 1, 2007. The plan provides these employees with the retirement benefits to which they would be entitled under the Duke Energy Retirement Cash Balance Plan but for certain limits contained in the Internal Revenue Code of 1986, as amended.
Severance. Duke Energy did not have a formal policy with respect to entering into employment agreements providing severance protections; however, certain severance protections were offered to executive officers of Duke Energy, including Mr. Fowler and Ms. Wyrsch, under agreements that were terminated in connection with the spin-off of Spectra Energy.
The Spectra Energy Compensation Committee believes that protection provided through severance arrangements is appropriate as it diminishes the potential distraction of the executives by virtue of the personal uncertainties and risks associated with their roles, especially in the context of a potential corporate restructuring or change in control. Accordingly, in connection with the spin-off of Spectra Energy, each Spectra Energy named executive officer entered into an agreement with Spectra Energy that address certain events that might occur in connection with a change in control of Spectra Energy. The terms of these agreements were approved by the Spectra Energy Compensation Committee and are described in greater detail under “Executive Compensation— Potential Payments upon Employment or Change in Control.”
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Compensation of the Chief Executive Officer
The compensation paid to Mr. Fowler in 2006 was established by the Duke Energy Compensation Committee in connection with his duties as Group Executive & President Duke Energy Gas Transmission. As such, Mr. Fowler’s compensation consisted of an annual base salary, an annual bonus opportunity, awards under Duke Energy’s long term incentive programs and other ancillary benefits as reported on the summary compensation table.
As discussed under “—Non Equity Incentive Compensation”, 80% of Mr. Fowler’s 2006 annual incentive opportunity was determined by performance based on an Earnings Per Share (EPS) goal and 20% of his opportunity was determined by performance on individual goals. Individual goals included building a high-performance culture focused on safety, diversity and inclusion, employee development and leadership; completing the divestiture of energy marketing and trading assets; completing the assessment and spin-off of the gas business; and developing a strategic plan supporting corporate objectives. If target performance on financial and individual goals were met, Mr. Fowler was eligible to earn 90% of his base salary as a bonus. Mr. Fowler was eligible to earn higher amounts if target performance was exceeded.
After adjusting for items that were not part of the 2006 business plan, Duke Energy’s ongoing EPS for 2006 was $1.89, resulting in a payout of 125% of the opportunity that was contingent on the EPS goal. Further, Mr. Fowler was deemed by the Duke Energy CEO and the Duke Energy Compensation Committee to have achieved 117.50% of his personal goals. Finally, all senior executives’ short-term incentives were reduced by 5% to reflect that the company did not achieve the safety goal of no Duke Energy employee, contractor or subcontractor fatalities in 2006. As a result of performance on all measures, the Duke Energy Compensation Committee approved and the Spectra Energy Compensation Committee ratified a bonus payment of $797,747 to Mr. Fowler.
In regard to his long term incentive opportunity as an executive of Duke Energy, Mr. Fowler was awarded 36,640 performance shares and 36,640 phantom shares according to the terms described under “Executive Compensation—Long-Term Incentive Awards Granted in 2006.” The value of this grant was determined by the Duke Energy Compensation Committee in consultation with its independent compensation advisor and was deemed by the Duke Energy Compensation Committee to be consistent with its philosophy regarding total direct compensation.
In regard to the total compensation opportunity established for Mr. Fowler as CEO of Spectra Energy, Duke Energy management worked with its outside compensation consultant to determine a market median total compensation package by reviewing market surveys. Accordingly, the Duke Energy Compensation Committee approved, and the Spectra Energy Compensation Committee subsequently approved, a 2007 base annual salary for Mr. Fowler of $950,000, an annual target cash incentive opportunity of 90% of base annual salary and an annual long-term incentive grant to be valued at 220% of base annual salary.
Other Compensation Policies
Stock Ownership Policy: Spectra Energy has adopted a stock ownership policy for executive officers and other key employees who receive long-term incentives. Each employee is required to satisfy the ownership target within five years after becoming subject to the policy. To reinforce the importance of stock ownership, an employee who is subject to the policy and who does not achieve his or her ownership target by the applicable date will become ineligible for future long-term incentives unless he or she elects to apply all short-term incentive payments to the purchase of Spectra Energy common stock until his or her target ownership level is achieved. The stock ownership guidelines are as follows:
Position | Number of Shares | |
President and Chief Executive Officer, Spectra Energy | 100,000 | |
President and Chief Executive Officer, Spectra Energy | 40,000 | |
Direct Reports to President and CEO, Spectra Energy, including the other Named Executive Officers | 28,000 | |
All Other Executives Subject to Guidelines | 2,000 -14,000 | |
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Corporate Transactions
Effective with the spin-off of Spectra Energy, equitable adjustments were made with respect to stock options and outstanding equity awards relating to Duke Energy common stock. All such awards were adjusted into two separate awards, one relating to Duke Energy common stock and one relating to Spectra Energy common stock. Such adjustment was made such that the number of shares relating to the award covering Spectra Energy common stock was equal to the number of shares of Spectra Energy common stock that the award holder would have received in the distribution had the Duke Energy award represented outstanding shares of Duke Energy common stock (i.e., a ratio of 0.5 shares of Spectra Energy common stock for every one share of Duke Energy common stock). With respect to stock options, the per share option exercise price of the original Duke Energy stock option was proportionally allocated between the two types of stock options taking into account the distribution ratio and the relative per share trading prices following the distribution. The resulting Duke Energy and Spectra Energy awards continue to be subject to the vesting schedule under the original Duke Energy award agreement. For purposes of vesting of options and phantom stock and the post-termination exercise periods applicable to the options, continued employment with Duke Energy or Spectra Energy is considered to be continued employment with the issuer of the options or shares of phantom stock. In the case of performance units, TSR is determined for periods following December 31, 2006, based on an equally-weighted average of the TSR of Duke Energy and the TSR of Spectra Energy. The adjustments preserved, but did not increase, the value of the equity awards.
Tax and Accounting Implications
Deductibility of Executive Compensation: The Duke Energy Compensation Committee reviewed and considered the deductibility of executive compensation under Section 162(m) of the Internal Revenue Code, which provides that Duke Energy generally may not deduct for federal income tax purposes annual compensation in excess of $1 million paid to certain employees. Performance-based compensation paid pursuant to shareholder-approved plans is not subject to the deduction limit as long as such compensation is approved by “outside directors” within the meaning of Section 162(m) of the Internal Revenue Code. During 2006, a Duke Energy Subcommittee for Performance-Based Compensation, which was comprised of those Duke Energy Compensation Committee members who qualified as “outside directors” within the meaning of Section 162(m) of the Internal Revenue Code, approved compensation that was intended to satisfy the performance-based compensation exception.
The Spectra Energy Compensation Committee has appointed a Subcommittee for Performance-Based Compensation to approve compensation 2007 opportunities intended to satisfy the performance-based compensation exception. The Spectra Energy Compensation Committee generally intends to structure and administer executive compensation plans and arrangements so that they will not be subject to the deduction limit of Section 162(m) of the Internal Revenue Code. The Spectra Energy Compensation Committee may from time to time approve payments that cannot be deducted in order to maintain flexibility in structuring appropriate compensation programs in the interest of shareholders. For example, phantom share awardsdescribed under “Compensation Discussion and Analysis—Elements of the Compensation Plan” received by certain employees may not be deductible for federal income tax purposes, depending on the amount and other types of compensation received by such employees.
Accounting for Stock-Based Compensation: Spectra Energy accounts for stock-based payments in accordance with the requirements of SFAS No. 123(R). Under this accounting pronouncement, Spectra Energy is required to value unvested stock options granted under the fair value method and expense those amounts in the income statement over the stock option’s remaining vesting period. Spectra Energy considers the expenses associated with the grant of options and other long-term incentive awards in granting such awards.
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Executive Compensation
The table below sets forth compensation from Duke Energy during 2006 to those individuals who became Spectra Energy’s named executive officers. In addition, the table sets forth compensation from Duke Energy during 2006 to Mr. Anderson, Spectra Energy’s non-executive Chairman.
SUMMARY COMPENSATION TABLE
Name and Principal Position | Year | Salary ($) | Bonus ($) | Stock Awards ($) (1) | Option Awards ($) (2) | Non-Equity Incentive Plan Compensation ($) (3) | Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) (4) | All Other Compensation ($) (5) | Total ($) | |||||||||
Paul M. Anderson (6) | 2006 | 0 | 0 | 2,131,143 | 533,595 | 0 | 59,048 | 791,798 | 3,515,584 | |||||||||
Chairman of the Board, Spectra Energy Corp (formerly Chairman of the Board, Duke Energy Corporation) | ||||||||||||||||||
Fred J. Fowler | 2006 | 755,496 | 0 | 3,094,314 | 63,326 | 797,747 | 324,035 | 148,601 | 5,183,519 | |||||||||
Chief Executive Officer and President, Spectra Energy Corp | ||||||||||||||||||
(formerly Group Executive & President, Duke Energy Gas Transmission) | ||||||||||||||||||
Gregory L. Ebel (7) | 2006 | 276,219 | 0 | 220,050 | 3,736 | 161,399 | 122,162 | 141,280 | 924,846 | |||||||||
Chief Financial Officer, Spectra Energy Corp | ||||||||||||||||||
(formerly President, Union Gas) | ||||||||||||||||||
Martha B. Wyrsch | 2006 | 527,502 | 0 | 1,000,761 | 11,342 | 496,725 | 102,612 | 71,604 | 2,210,546 | |||||||||
Chief Executive Officer and President, Spectra Energy Transmission | ||||||||||||||||||
(formerly President, Duke Energy Gas Transmission) | ||||||||||||||||||
Alan N. Harris | 2006 | 294,996 | 0 | 322,641 | 6,460 | 177,396 | 37,498 | 41,395 | 880,386 | |||||||||
Chief Development Officer, Spectra Energy Corp | ||||||||||||||||||
(formerly Group Vice President & Chief Financial Officer, Duke Energy Gas Transmission) | ||||||||||||||||||
William S. Garner, Jr. (8) | 2006 | 201,999 | 0 | 114,219 | 0 | 124,101 | 9,541 | 13,665 | 463,525 | |||||||||
General Counsel & Corporate Secretary, Spectra Energy Corp | ||||||||||||||||||
(formerly Group Vice President Corporate Development, Duke Energy Gas Transmission) | ||||||||||||||||||
| (1) | This column reflects the aggregate dollar amount recognized for financial statement reporting purposes for 2006 with respect to outstanding performance share and phantom share awards, and includes amounts attributable to performance share and phantom share awards granted in prior years. The aggregate dollar amount was determined in accordance with the provisions of SFAS 123(R), but without regard to any estimate of forfeitures related to service-based vesting conditions. See Note 18 of the Consolidated Financial Statements in Spectra Energy Capital’s Form 10-K for the year ended December 31, 2006 regarding assumptions underlying the valuation of equity awards. In addition, Mr. Anderson forfeited 3,500 performance shares as a result of Duke Energy not meeting its 2006 safety objective. |
| (2) | This column reflects the aggregate dollar amount recognized for financial statement reporting purposes for 2006 with respect to outstanding stock options, and includes amounts attributable to stock options granted in prior years. The aggregate dollar amount was determined in accordance with the provisions of SFAS 123(R), but without regard to any estimate of forfeitures related to service-based vesting conditions. See Note 18 of the Consolidated Financial Statements in Spectra Energy Capital’s Form 10-K for the year ended December 31, 2006 regarding assumptions underlying the valuation of equity awards. |
| (3) | Non-Equity Incentive Plan Compensation column includes amounts payable under the Duke Energy Corporation Executive Short-Term Incentive Plan with respect to the 2006 performance period. Unless deferred, these amounts were paid in March 2007. |
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| (4) | Change in Pension Value and Nonqualified Deferred Compensation Earnings column includes the amounts listed below. With respect to pension plans, these amounts relate to the one-year period ending on September 30, 2006, which is the applicable pension plan measurement date. With respect to above-market interest on deferred compensation arrangements, these amounts relate to the one-year period ending on December 31, 2006 |
| Paul M. Anderson | Fred J. Fowler | Gregory L. Ebel | Martha B. Wyrsch | Alan N. Harris | William S. Garner, Jr. | |||||||
Change in Actuarial Present Value of Accumulated Benefit Under the Duke Energy Retirement Cash Balance Plan for the One- Year Period Ending on September 30, 2006 | 0 | 51,691 | 1,789 | 22,340 | 2,422 | 9,346 | ||||||
Change in Actuarial Present Value of Accumulated Benefit Under the Duke Energy Executive Cash Balance Plan for the One- Year Period Ending on September 30, 2006 | 0 | 272,344 | 390 | 80,272 | 35,076 | 195 | ||||||
Change in Actuarial Present Value of Accumulated Benefit Under the Pension Choices Plan for Employees of Westcoast Energy Inc. and Affiliated Companies for the One-Year Period Ending on September 30, 2006 | 0 | 0 | 20,716 | 0 | 0 | 0 | ||||||
Change in Actuarial Present Value of Accumulated Benefit Under the Duke Energy Supplemental Pension Plan for the One- Year Period Ending on September 30, 2006 | 0 | 0 | 99,266 | 0 | 0 | 0 | ||||||
Above-Market Interest Earned on Amount Deferred under the Texas Eastern Corporation Deferred Income Program | 59,048 | 0 | 0 | 0 | 0 | 0 | ||||||
Total | 59,048 | 324,035 | 122,162 | 102,612 | 37,498 | 9,541 | ||||||
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| (5) | All Other Compensation column includes the following for 2006: |
| Paul M. Anderson | Fred J. Fowler | Gregory L. Ebel | Martha B. Wyrsch | Alan N. Harris | William S. Garner, Jr. | |||||||
Personal Use of Airplane | 190,564 | 11,305 | 0 | 4,729 | 8,244 | 0 | ||||||
Matching Contributions Under the Duke Energy Retirement Savings Plan | 0 | 13,200 | 0 | 13,200 | 13,200 | 11,920 | ||||||
Premiums for Life Insurance Coverage Provided Under Life Insurance Plans | 0 | 7,524 | 0 | 1,684 | 1,490 | 1,745 | ||||||
Matching Contributions Under the Westcoast Energy Inc. Executive Share Purchase Plan | 0 | 0 | 30,603 | 0 | 0 | 0 | ||||||
Make-Whole Matching Contribution Credits Under the Duke Energy Corporation Executive Savings Plan | 0 | 99,903 | 0 | 46,991 | 17,928 | 0 | ||||||
Reimbursement of Relocation Expenses | 324,971 | 0 | 0 | 0 | 0 | 0 | ||||||
Tax Gross-Up on Reimbursement of Relocation Expenses | 270,918 | 0 | 0 | 0 | 0 | 0 | ||||||
Club Dues | 0 | 10,495 | 432 | 0 | 275 | 0 | ||||||
Tax Gross-Up on Club Dues | 0 | 6,174 | 374 | 0 | 158 | 0 | ||||||
Charitable contributions made in the name of the Executive under Duke Energy’s matching gift policy. | 5,000 | 0 | 422 | 5,000 | 100 | 0 | ||||||
Reimbursement of taxes representing the difference between Canadian taxes paid by Mr. Ebel on his income from Duke Energy versus the U.S. taxes Mr. Ebel would have paid on such income had it been earned in the U.S., pursuant to a tax equalization arrangement in connection with Mr. Ebel’s assignment in Canada. | 0 | 0 | 71,686 | 0 | 0 | 0 | ||||||
Principal and imputed interest associated with a loan to Mr. Ebel that was partially forgiven by Duke Energy pursuant to the terms of a promissory note dated June 12, 2002. | 0 | 0 | 21,657 | 0 | 0 | 0 | ||||||
Tax gross-up amounts associated with Mr. Ebel’s loan | 0 | 0 | 16,106 | 0 | 0 | 0 | ||||||
Holiday Gift | 345 | 0 | 0 | 0 | 0 | 0 | ||||||
Total | 791,798 | 148,601 | 141,280 | 71,604 | 41,395 | 13,665 | ||||||
The amounts shown as “Personal Use of Airplane” reflect the personal use of Duke Energy’s aircraft by the named executive officers. In general, other than Mr. Anderson, the named officers were not allowed to initiate personal trips on corporate or charted aircraft. However, officers were permitted occasionally to invite their spouse or guests to accompany them on business trips when space was available. When the spouse’s or guest’s travel costs did not meet the IRS standard for “business use”, the flight was imputed as income to the officer even though such travel may not have resulted in incremental cost to Duke Energy. The methodology used to compute the incremental cost of this benefit was based on the hourly variable cost for the use of the aircraft, plus any tax deduction disallowance. Mr. Ebel’s spouse traveled with him occasionally on chartered aircraft for business trips, however, none of her travel resulted in incremental cost to Duke Energy.
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Duke Energy presented a holiday gift in 2006 to each director on the Board of Directors of Duke Energy as of December 31, 2006, including Mr. Anderson.
| (6) | Mr. Anderson did not receive a salary or bonus from Duke Energy during 2006 because he entered into an employment agreement with Duke Energy that provided compensation primarily through stock-based awards. |
| (7) | Most of Mr. Ebel’s 2006 compensation was provided in Canadian dollars and that portion of his compensation has been converted to U.S. dollars using the Tokyo Bloomberg closing rate of $0.8632 on December 29, 2006. |
| (8) | Mr. Garner was hired as Chief Development Officer of Duke Energy Gas Transmission on March 10, 2006, and was not compensated by Duke Energy prior to that date. |
Non Equity Incentive Compensation
As previously described, short-term incentive opportunities are provided to the Spectra Energy named executive officers. Depending on actual performance, participants are eligible to receive up to 190% of the amount of their short-term incentive target. The Spectra Energy named executive officers were provided with the following target incentive opportunities for 2006:
Name | Target Incentive Opportunity (as a % of base salary) | ||
Fred J. Fowler | 90 | % | |
Gregory L. Ebel | 50 | % | |
Martha B. Wyrsch | 80 | % | |
Alan N. Harris | 50 | % | |
William S. Garner, Jr. | 50 | % |
In 2006, the performance goals for each Spectra Energy named executive officer were weighted as follows:
Incentive Goals | Mr. Fowler | Mr. Ebel, Ms. Wyrsch, Mr. Harris and Mr. Garner | ||||
Corporate Goal | 80 | % | 40 | % | ||
Business Unit Goal(s) | 0 | % | 40 | % | ||
Individual Objectives | 20 | % | 20 | % |
The 2006 corporate goal consisted of ongoing basic EPS for Duke Energy, with $1.75, $1.90 and $2.10 constituting the threshold, target and maximum performance levels, respectively. Following the completion of the 2006 performance period, the Duke Energy Compensation Committee reduced the threshold, target and maximum EPS performance levels for the 2006 ongoing EPS goal to $1.69, $1.84 and $2.04, respectively, to reflect the divesture of Duke Energy’s marketing and trading business as well as the partial divestiture of Crescent Resources. After adjusting for certain items that were not part of the 2006 business plan, as contemplated in the pre-established 2006 short-term incentive program guidelines, Duke Energy achieved ongoing EPS of $1.89, resulting in a payout of 125% with respect to the corporate goal.
During 2006, the individual goals of the Spectra Energy named executive officers consisted of a combination of strategic and operational objectives. Mr. Fowler’s individual goals were based on continuing to build a high performance culture focused on safety, diversity and inclusion, employee development, leadership; completing the divestiture of the energy marketing and trading assets; completing the assessment and spin-off of the gas businesses; and developing a strategic plan supporting corporate objectives. Other Spectra Energy named executive officers had common goals on which their individual performance was measured including execution on existing plans and projects on time and on budget, improving safety, establishing a high-performance culture and strengthening external stakeholder relationships. In addition, Ms. Wyrsch’s individual goals included advancement of the Duke Energy Gas Transmission (DEGT) growth strategy, Mr. Ebel’s goals included advancement of Union Gas’s long term growth strategy, Mr. Garner’s goals included development of a corporate development team and corporate development function and preparing a strategy and approach for an MLP, and Mr. Harris’ goals included O&M cost reductions and advancement of the DEGT growth strategy. Over the last five years, the achievement level of participants in the STI Plan has exceeded target performance, but has been less than maximum performance.
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Based on an evaluation of performance during 2006, the Duke Energy Compensation Committee approved and the Spectra Energy Compensation Committee was apprised of the payments to Messrs. Fowler and Ebel, Ms. Wyrsch and Messrs. Harris and Garner representing 117%, 117%, 121%, 120% and 123%, of their respective target awards. The actual payments to each of the Spectra Energy named executive officers were reduced by 5% as a result of not achieving Duke Energy’s safety goals during 2006.
Long-Term Incentive Awards Granted in 2006
The target 2006 long-term incentive opportunities, expressed as a percentage of base salary, for Messrs. Fowler and Ebel, Ms. Wyrsch and Messrs. Harris and Garner were 280%, 75%, 200%, 100%, and 75%, respectively. 50% of the value of the 2006 target long-term incentive opportunity of each Spectra Energy named executive officer (other than Mr. Anderson, who did not participate in this program in 2006), was awarded under the Duke Energy 1998 Long-Term Incentive Plan in the form of performance shares and 50% was awarded in the form of phantom shares.
One-fifth of the 2006 phantom share award vests on each of the first five anniversaries of the grant date provided the recipient continues to be employed by Duke Energy or his or her employment terminates by reason of retirement. If the recipient’s employment terminates as a result of death, disability, or by Duke Energy without cause or as a result of a divestiture, units in the award are prorated to reflect actual service during the installment vesting period and are immediately vested, and any remaining unvested units are forfeited. In the event employment is terminated by Duke Energy without cause within two years following a “change in control” of Duke Energy, all outstanding unvested units will vest. Vesting ceases if, at the time the recipient’s Duke Energy employment terminates, he or she is retirement eligible and subsequently becomes employed by, or otherwise provides service to, a Duke Energy competitor to the detriment of Duke Energy. Dividend equivalents are paid on phantom shares that have not yet vested or been forfeited. In connection with the spin-off of Spectra Energy, these awards were adjusted to provide that employment with Spectra Energy is the equivalent of employment with Duke Energy in determining whether continuing employment requirements are met.
The performance shares generally will vest only to the extent that Duke Energy’s total shareholder return (TSR) targets for the three-year period from January 1, 2006 to December 31, 2008 are met as compared with the TSR of a peer group of companies. TSR refers to the change in fair market value over a specified period of time, expressed as a percentage of an initial investment in common stock, with dividends reinvested and with the average TSR for the final 30 business days of the period considered the TSR at the end of the period. For this purpose, Duke Energy’s peer group consists of the companies in the S&P 500. The following table illustrates how the performance share payouts directly align participants’ pay to Duke Energy’s performance:
Relative TSR Performance Percentile | Percent Payout of Target Performance Shares | |
75th Percentile or above | 150% | |
58.33 Percentile (Target) | 100% | |
40th Percentile | 50% | |
Below 40th Percentile | 0% | |
Notwithstanding Duke Energy’s relative TSR as compared to the companies in the S&P 500, the performance shares that were granted in 2006 provide that if Duke Energy’s relative TSR ranking among the S&P 500 Utility Index companies is less than the 60th percentile, the Duke Energy Compensation Committee is authorized to exercise discretion to reduce or eliminate any vesting of performance shares that would otherwise occur.
Earned performance shares are paid following the determination in early 2009 of the extent to which the performance goal has been achieved, unless an election (to the extent permitted by applicable law) is made by the executive to defer payment of the performance shares until termination of employment. Any shares not earned are forfeited. In addition, following a determination that the performance goal has been achieved, participants will receive a cash payment equal to the amount of cash dividends paid on one share of Duke Energy common stock during the performance period multiplied by the number of performance shares earned, unless an election is made by the executive to defer payment of the performance shares and tandem dividend equivalents until termination of employment. If the recipient’s employment terminates during the performance period as a result of
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retirement, death, disability, or by Duke Energy without cause or as a result of a divestiture, following determination that the TSR goal has been achieved, the number of shares earned will be adjusted to reflect actual service during the performance period. If the recipient’s employment terminates during the performance period for any other reason, all shares covered by the award are forfeited. In the event of a “change in control” prior to December 31, 2008, achievement of target TSR performance is assumed and the number of shares earned is adjusted to reflect actual service during the performance period prior to the change in control. Vesting ceases if, at the time the recipient’s Duke Energy employment terminates, he or she is retirement eligible and subsequent to such termination of employment becomes employed by, or otherwise provides service to, a Duke Energy competitor to the detriment of Duke Energy. Effective with the spin-off of Spectra Energy into an independent entity, awards were adjusted as described in the Corporate Transactions section of the Compensation Discussion and Analysis.
Compensation of Mr. Anderson
The employment agreement between Duke Energy and Mr. Anderson established that Mr. Anderson’s compensation would be provided primarily in the form of stock-based compensation in lieu of base salary, annual cash incentives and certain employee benefits. The purpose of the structure of this compensation package was to directly align Mr. Anderson’s compensation with shareholders by making his compensation contingent upon stock price, Duke Energy performance and dividend yield. In accordance with his employment agreement, upon commencement of his employment with Duke Energy in November 2003, Mr. Anderson received a nonqualified stock option award with respect to 1,100,000 shares, a performance share award for 360,000 shares and a phantom share award for 285,000 units.
On April 4, 2006, Mr. Anderson’s employment agreement was amended to reflect the changes to Mr. Anderson’s employment status upon closing of the merger of Duke Energy with Cinergy Corp. and certain other matters. Prior to its amendment, Mr. Anderson’s employment agreement provided him a performance share award covering up to 120,000 shares of common stock for 2006. Mr. Anderson agreed that, in light of the change in his role and responsibilities, his maximum performance share award for 2006 would be reduced to 70,000 shares. The vesting of 30,000 of these performance shares continued to be based on the same factors established in February 2006, such that 80% was based on the same EPS goal applicable under the STI plan for 2006 with the remaining 20% being based on previously-established strategic objectives (which consisted of strategic goals relating to such things as completion of the merger with Cinergy Corp.; building a high performance culture focused on safety, diversity and inclusion, employee development, leadership and results; delivering on 2006 financial objectives; positioning the company for growth in 2007 and beyond; completion of the divestiture of the energy marketing and trading segment; building credibility through leadership on key policy issues, transparent communications and excellent customer service). The vesting of the remaining 40,000 performance shares was based on the extent to which Mr. Anderson was determined to have attained strategic objectives established shortly following the merger with Cinergy Corp. based on his success in resolving the issue of desirability of separating the gas and electric businesses in a manner that creates shareholder value, achieving a successful integration of Cinergy Corp., resolving strategic issues, and enhancing shareholder value by being an external voice for Duke Energy to the investment community. The performance shares could be earned in full if target performance were achieved on an aggregate basis, such that Mr. Anderson could have earned a full payout of his performance shares if performance were above target with respect to one performance objective and below target on the other. Mr. Anderson could not have received more than 70,000 performance shares for 2006 even if aggregate performance exceeded target.
In order to assume his role as Chairman of the Board of Directors of Spectra Energy, Mr. Anderson’s employment relationship with Duke Energy terminated on January 2, 2007, at which time he became eligible to receive payment of his vested performance shares and phantom shares. Mr. Anderson’s vested stock options became exercisable in accordance with their terms on January 1, 2007.
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2006 GRANTS OF PLAN-BASED AWARDS
| Grant Date | Committee Approval Date | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) | Estimated Future Payouts Plan Awards (2) | All Other Units
(#) (2)
| Grant Date Awards ($) (3) | ||||||||||||||||||||
| Name | Threshold ($) | Target ($) | Maximum ($) | Threshold (#) | Target (#) | Maximum (#) | |||||||||||||||||||
Fred J. Fowler | $ | 339,973 | $ | 679,946 | $ | 1,291,898 | |||||||||||||||||||
Fred J. Fowler | 4/4/2006 | 4/4/2006 | 18,320 | 36,640 | 54,960 | $ | 648,894 | ||||||||||||||||||
Fred J. Fowler | 4/4/2006 | 4/4/2006 | 36,640 | $ | 1,067,690 | ||||||||||||||||||||
Gregory L. Ebel | $ | 69,055 | $ | 138,110 | $ | 262,408 | |||||||||||||||||||
Gregory L. Ebel | 4/4/2006 | 4/4/2006 | 1,777 | 3,553 | 5,330 | $ | 62,930 | ||||||||||||||||||
Gregory L. Ebel | 4/4/2006 | 4/4/2006 | 3,550 | $ | 103,447 | ||||||||||||||||||||
Martha B. Wyrsch | $ | 204,938 | $ | 409,877 | $ | 778,765 | |||||||||||||||||||
Martha B. Wyrsch | 4/4/2006 | 4/4/2006 | 7,770 | 15,540 | 23,310 | $ | 275,213 | ||||||||||||||||||
Martha B. Wyrsch | 4/4/2006 | 4/4/2006 | 15,540 | $ | 452,836 | ||||||||||||||||||||
Martha B. Wyrsch | 7/1/2006 | (4) | 6/26/2006 | 1,750 | 3,500 | 5,250 | $ | 61,740 | |||||||||||||||||
Martha B. Wyrsch | 7/1/2006 | (4) | 6/26/2006 | 3,500 | $ | 102,795 | |||||||||||||||||||
Alan N. Harris | $ | 73,749 | $ | 147,498 | $ | 280,246 | |||||||||||||||||||
Alan N. Harris | 4/4/2006 | 4/4/2006 | 2,557 | 5,113 | 7,670 | $ | 90,557 | ||||||||||||||||||
Alan N. Harris | 4/4/2006 | 4/4/2006 | 5,110 | $ | 148,905 | ||||||||||||||||||||
William S. Garner, Jr. | $ | 50,500 | $ | 101,000 | $ | 191,899 | |||||||||||||||||||
William S. Garner, Jr. | 4/1/2006 | (5) | 4/1/2006 | 5,000 | $ | 145,750 | |||||||||||||||||||
William S. Garner, Jr. | 5/10/2006 | (6) | 5/10/2006 | 1,537 | 3,073 | 4,610 | $ | 54,091 | |||||||||||||||||
William S. Garner, Jr. | 5/10/2006 | (6) | 5/10/2006 | 3,070 | $ | 88,048 | |||||||||||||||||||
| (1) | The awards reflected in the Estimated Possible Payouts Under Non-Equity Incentive Plan Awards column were granted for the 2006 performance period under the terms of the Duke Energy Corporation Executive Short-Term Incentive Plan. The actual amounts payable to each executive under the terms of such plan for 2006 are disclosed in the Summary Compensation Table. |
| (2) | All awards reflected in these columns were made in shares of Duke Energy common stock and were granted under the terms of the Duke Energy Corporation 1998 Long-Term Incentive Plan. |
| (3) | The per share full grant date fair value of the phantom shares granted on April 1, 2006, computed in accordance with FASB 123(R) is $29.15. The per share full grant date fair values of the phantom shares and performance shares granted on April 4, 2006, computed in accordance with FASB 123(R), are $29.14 and $17.71, respectively. The per share full grant date fair values of the phantom shares and performance shares granted on May 10, 2006 are $28.68 and $17.60, respectively. The per share full grant date fair values of the phantom shares and performance shares granted on July 1, 2006 are $29.37 and $17.64, respectively. |
| (4) | The Duke Energy Compensation Committee, at its meeting on June 26, 2006, approved an incremental grant of phantom shares and performance shares to reflect an increase in Ms. Wyrsch’s responsibilities. For purposes of determining the vesting of these awards, the grant date is treated as being on April 4, 2006, which is the same grant date as other 2006 awards under the Duke Energy 2006 long-term incentive program. |
| (5) | The Duke Energy Chief Executive Officer approved a restricted stock award on April 1, 2006 upon the hiring of Mr. Garner. This award vests, subject to certain exceptions, in equal installments on the first three anniversaries of the date of grant. |
| (6) | The Duke Energy Compensation Committee, at its meeting on May 10, 2006, provided Mr. Garner with a grant of phantom shares and performance shares to reflect his annual award, as he was hired after January 1, 2006. For purposes of determining the vesting of these awards, the grant date is treated as being on April 4, 2006, which is the same grant date as other awards under the Duke Energy 2006 long-term incentive program. |
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OUTSTANDING EQUITY AWARDS AT 2006 FISCAL YEAR-END
| Option Awards | Stock Awards | ||||||||||||||||||||
| Name | Number of
(#) Exercisable | Number of
(#) Unexercisable | Equity
(#) | Option
($) (2) | Option Expiration Date | Number of Vested
(#) (3) | Market Value
($) | Equity
(#) (4) | Equity
($) | ||||||||||||
Paul M. Anderson | 1,100,000 | $ | 17.45 | 11/17/2013 | |||||||||||||||||
Paul M. Anderson | 20,000 | $ | 664,200 | ||||||||||||||||||
Fred J. Fowler | 400,000 | $ | 29.47 | 4/16/2008 | |||||||||||||||||
Fred J. Fowler | 157,000 | $ | 24.88 | 12/20/2009 | |||||||||||||||||
Fred J. Fowler | 104,000 | $ | 42.81 | 12/20/2010 | |||||||||||||||||
Fred J. Fowler | 119,000 | $ | 37.68 | 12/19/2011 | |||||||||||||||||
Fred J. Fowler | 42,100 | $ | 38.33 | 1/17/2012 | |||||||||||||||||
Fred J. Fowler | 150,750 | 50,250 | $ | 13.77 | 2/25/2013 | ||||||||||||||||
Fred J. Fowler | 73,024 | $ | 2,425,127 | ||||||||||||||||||
Fred J. Fowler | 41,060 | $ | 1,363,603 | ||||||||||||||||||
Gregory L. Ebel | 462 | $ | 28.06 | 4/29/2008 | |||||||||||||||||
Gregory L. Ebel | 1,233 | $ | 23.40 | 4/29/2009 | |||||||||||||||||
Gregory L. Ebel | 9,021 | $ | 19.98 | 11/30/2009 | |||||||||||||||||
Gregory L. Ebel | 2,159 | $ | 20.57 | 4/25/2010 | |||||||||||||||||
Gregory L. Ebel | 2,930 | $ | 27.45 | 2/16/2011 | |||||||||||||||||
Gregory L. Ebel | 4,163 | $ | 33.53 | 2/12/2012 | |||||||||||||||||
Gregory L. Ebel | 2,900 | $ | 31.10 | 7/1/2012 | |||||||||||||||||
Gregory L. Ebel | 6,450 | 2,150 | $ | 13.77 | 2/25/2013 | ||||||||||||||||
Gregory L. Ebel | 6,110 | $ | 202,913 | ||||||||||||||||||
Gregory L. Ebel (5) | 13,377 | $ | 444,234 | ||||||||||||||||||
Martha B. Wyrsch | 15,600 | $ | 27.94 | 10/1/2009 | |||||||||||||||||
Martha B. Wyrsch | 38,000 | $ | 24.88 | 12/20/2009 | |||||||||||||||||
Martha B. Wyrsch | 27,600 | $ | 42.81 | 12/20/2010 | |||||||||||||||||
Martha B. Wyrsch | 30,000 | $ | 37.68 | 12/19/2011 | |||||||||||||||||
Martha B. Wyrsch | 2,500 | $ | 38.33 | 1/17/2012 | |||||||||||||||||
Martha B. Wyrsch | 27,000 | 9,000 | $ | 13.77 | 2/25/2013 | ||||||||||||||||
Martha B. Wyrsch (6) | 56,760 | $ | 1,885,000 | ||||||||||||||||||
Martha B. Wyrsch (7) | 18,096 | $ | 600,968 | ||||||||||||||||||
Alan N. Harris | 4,000 | $ | 27.63 | 2/17/2008 | |||||||||||||||||
Alan N. Harris | 5,650 | $ | 29.66 | 2/17/2009 | |||||||||||||||||
Alan N. Harris | 10,500 | $ | 24.88 | 12/20/2009 | |||||||||||||||||
Alan N. Harris | 7,400 | $ | 42.81 | 12/20/2010 | |||||||||||||||||
Alan N. Harris | 8,200 | $ | 37.68 | 12/19/2011 | |||||||||||||||||
Alan N. Harris | 4,100 | $ | 38.33 | 1/17/2012 | |||||||||||||||||
Alan N. Harris | 2,700 | $ | 37.80 | 4/1/2012 | |||||||||||||||||
Alan N. Harris | 3,200 | $ | 13.77 | 2/25/2013 | |||||||||||||||||
Alan N. Harris | 1,400 | $ | 14.54 | 4/1/2013 | |||||||||||||||||
Alan N. Harris (8) | 19,270 | $ | 639,957 | ||||||||||||||||||
Alan N. Harris | 5,157 | $ | 171,247 | ||||||||||||||||||
William S. Garner, Jr. (9) | 8,070 | $ | 268,005 | ||||||||||||||||||
William S. Garner, Jr. (9) | 1,537 | $ | 51,027 | ||||||||||||||||||
| All option and stock awards reflected in the table relate to shares of Duke Energy common stock. |
| (1) | On November 17, 2003, Mr. Anderson received a grant of a stock option covering 1,100,000 shares of Duke Energy common stock that vested in three equal installments on each of the first three anniversaries of the date of grant and that became exercisable on January 1, 2007. On February 25, 2003 (and April 1, 2003, with respect to Mr. Harris) , Messrs. Fowler and Ebel, Ms. Wyrsch and Mr. Harris received stock options that vest in four equal installments on the first four anniversaries of the date of grant; the remaining 25% of these stock options vested on February 25, 2007. |
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| (2) | The exercise price is equal to the closing price of Duke Energy common stock on the date of grant. In connection with the spin-off of Spectra Energy effective January 2, 2007 all Duke Energy equity awards were adjusted to reflect the change in the price of Duke Energy common stock that occurred as a result of the spin-off, and an additional award was granted that related to Spectra Energy common stock. Please see “Compensation Discussion and Analysis—Corporate Transactions.” The adjustments preserved, but did not increase, the value of the equity awards. The following chart indicates the original and adjusted exercise prices of each stock option for Duke. In addition, the chart indicates exercise prices for stock options granted on January 2, 2007 at Spectra Energy associated to each grant date at Duke Energy: |
| Date of Grant | Duke Original Option Exercise Price | Duke Adjusted Option Exercise Price | Spectra Option Exercise Price Granted on January 2, 2007 | ||||||
February 17, 1998 | $ | 27.63 | $ | 15.74 | $ | 23.79 | |||
April 29, 1998 | $ | 28.06 | $ | 15.99 | $ | 24.16 | |||
February 17, 1999 | $ | 29.66 | $ | 16.90 | $ | 25.53 | |||
April 29, 1999 | $ | 23.40 | $ | 13.33 | $ | 20.15 | |||
October 1, 1999 | $ | 27.94 | $ | 15.92 | $ | 24.05 | |||
November 30, 1999 | $ | 19.98 | $ | 11.39 | $ | 17.20 | |||
December 20, 1999 | $ | 24.88 | $ | 14.17 | $ | 21.42 | |||
April 25, 2000 | $ | 20.57 | $ | 11.72 | $ | 17.71 | |||
December 20, 2000 | $ | 42.81 | $ | 24.39 | $ | 38.86 | |||
February 16, 2001 | $ | 27.45 | $ | 15.64 | $ | 23.64 | |||
December 19, 2001 | $ | 37.68 | $ | 21.47 | $ | 32.44 | |||
January 17, 2002 | $ | 38.33 | $ | 21.84 | $ | 33.00 | |||
February 12, 2002 | $ | 33.53 | $ | 19.10 | $ | 28.87 | |||
April 1, 2002 | $ | 37.80 | $ | 21.54 | $ | 32.54 | |||
July 1, 2002 | $ | 31.10 | $ | 17.72 | $ | 26.78 | |||
February 25, 2003 | $ | 13.77 | $ | 7.85 | $ | 11.86 | |||
April 1, 2003 | $ | 14.54 | $ | 8.29 | $ | 12.52 | |||
| (3) | On November 17, 2003, Mr. Anderson received a grant of 285,000 phantom shares, the last 20,000 of which became vested on January 1, 2007. Messrs. Fowler and Ebel, Ms. Wyrsch and Mr. Harris received phantom shares on February 28, 2005 and April 4, 2006, each of which, subject to certain exceptions, vests in equal installments on the first five anniversaries of the date of grant. |
| (4) | Messrs. Fowler and Ebel, Ms. Wyrsch and Mr. Harris received performance shares on February 28, 2005 and April 4, 2006 that, subject to certain exceptions, are eligible for vesting on December 31, 2007 and December 31, 2008, respectively. Ms. Wyrsch received performance shares on June 26, 2006 and Mr. Garner received performance shares on May 10, 2006 that, subject to certain exceptions, are eligible for vesting on December 31, 2008. Pursuant to Instruction 3 to Item 402(f)(2) of Regulation S-K, performance shares are listed at the threshold number of shares. |
| (5) | On January 1, 2004, Mr. Ebel received a grant of 10,000 performance shares. 3,333 performance shares vested on January 1, 2007 as a result of performance criteria being met. The remaining performance shares will vest, subject to certain exceptions, on January 1, 2011. |
| (6) | On September 20, 2000, Ms. Wyrsch received a grant of 24,000 performance shares (shares reflect Duke Energy 2-for-1 stock split in 2001) with accelerated vesting criteria based on total shareholder return. The total shareholder return criteria was not achieved and accordingly the shares will vest, subject to certain exceptions, on the seventh anniversary of the date of grant. |
| (7) | Ms. Wyrsch received performance shares and phantom shares on July 1, 2006. For purposes of determining the vesting of these awards, the grant date is treated as being on April 4, 2006, which is the same grant date as other awards under the Duke Energy 2006 long-term incentive program. |
| (8) | Mr. Harris received an award of 10,000 restricted shares on February 1, 2005 and which vest, subject to certain exceptions, on the fifth anniversary of the date of grant. |
| (9) | Mr. Garner received an award of 5,000 restricted shares on April 1, 2006 which vest, subject to certain exceptions, in equal installments on the first three anniversaries of the date of grant. Mr. Garner also received performance shares and phantom shares on May 10, 2006. For purposes of determining the vesting of these awards, the grant date is treated as being on April 4, 2006, which is the same grant date as other awards under the Duke Energy 2006 long-term incentive program. |
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2006 OPTION EXERCISES AND STOCK VESTED
| Option Awards | Stock Awards | |||||||
| Name | Number of Shares (#) | Value Realized on ($) (1) | Number of (#) (2) (3) | Value Realized on ($) (4) | ||||
Paul M. Anderson | 0 | $0 | 146,500 | $4,531,865 | ||||
Fred J. Fowler | 20,888 | $128,208 | 158,434 | $5,246,688 | ||||
Gregory L. Ebel | 0 | $0 | 7,452 | $254,177 | ||||
Martha B. Wyrsch | 0 | $0 | 44,291 | $1,513,024 | ||||
Alan N. Harris | 4,600 | $69,854 | 11,688 | $398,425 | ||||
William S. Garner, Jr. | 0 | $0 | 0 | $0 | ||||
| (1) | The value realized upon exercise was calculated based on the closing price of a share of Duke Energy common stock on the date of option exercise. |
| (2) | The executives elected to defer the following number and amount of vested stock awards pursuant to the Duke Energy Corporation Executive Savings Plan as follows: Mr. Fowler 85,088 shares ($2,645,470); Mr. Ebel 4,004 shares ($132,973); Ms. Wyrsch 0 shares ($0); Mr. Harris 0 shares ($0) and Mr. Garner 0 shares ($0). |
| (3) | Includes performance shares covering the 2004 - 2006 performance period and phantom shares that accelerated based on Duke Energy’s total shareholder return performance during the 2004-2006 performance period. The Duke Energy Compensation Committee certified the achievement of the applicable performance measures on February 22, 2007 and the results were reviewed by the Spectra Energy Compensation Committee on February 26, 2007. |
| (4) | The value realized upon vesting of stock awards was calculated based on the closing price of a share of Duke Energy common stock on the respective vesting date, and includes a cash payment to Messrs. Fowler and Ebel, Ms. Wyrsch and Mr. Harris for dividend equivalents on earned performance shares in the amount of $209,135, $13,032, $78,162 and $20,364, respectively. |
Duke Energy provides pension benefits that are intended to assist its retirees with their retirement income needs. A more detailed description of the plans that comprise Duke Energy’s pension program follows.
Duke Energy Energy Retirement Cash Balance Plan and Executive Cash Balance Plan
Each of the Spectra Energy named executive officers actively participated in pension plans sponsored by Duke Energy or an affiliate in 2006. Officers other than Mr. Ebel participated in the Duke Energy Retirement Cash Balance Plan (“RCBP”), which is a noncontributory, defined benefit retirement plan that is intended to satisfy the requirements for qualification under Section 401(a) of the Internal Revenue Code. The RCBP generally covers non-bargaining employees of Duke Energy and affiliates. The RCBP provides benefits under a “cash balance account” formula. Mr. Anderson has an accrued benefit under the RCBP, but his benefit is “frozen” (i.e., it does not grow based on his continued service and pay).
Each of the Spectra Energy named executive officers who participates in the RCBP has satisfied the eligibility requirements to receive his or her account benefit upon termination of employment. The RCBP benefit is payable in the form of a lump sum in the amount credited to the hypothetical account at the time of benefit commencement. Payment is also available in the form of an annuity based on the actuarial equivalent of the account balance.
The amount credited to the hypothetical account is increased with monthly pay credits equal to (i) for participants with combined age and service of less than 35 points, 4% of eligible monthly compensation, (ii) for participants with combined age and service of 35 to 49 points, 5% of eligible monthly compensation, (iii) for participants with combined age and service of 50 to 64 points, 6% of eligible monthly compensation, and (iv) for participants with combined age and service of 65 or more points, 7% of eligible monthly compensation. If the participant earns more than the Social Security wage base, the account is credited with additional pay credits equal to 4% of eligible compensation above the Social Security wage base. Interest credits are credited monthly, with the interest rate determined quarterly based on the 30-year Treasury rate.
For the RCBP, eligible monthly compensation is equal to Form W-2 wages, plus elective deferrals under a 401(k) or cafeteria plan. Compensation does not include severance pay (including payment for unused vacation), expense reimbursements, allowances, cash or noncash fringe benefits, moving expenses, bonuses for performance periods in excess of one year, transition pay, long term incentive compensation (including income resulting from any stock-based awards such as stock options, stock appreciation rights, phantom stock or restricted stock) and other compensation items to the extent described as not included for purposes of benefit plans or the RCBP.
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The benefit of participants in the RCBP may not be less than determined under certain prior benefit formulas (including optional forms). In addition, the benefit under the RCBP is limited by maximum benefits and compensation limits under the Internal Revenue Code.
Each of the Spectra Energy named executive officers other than Mr. Ebel were eligible to participate in the Duke Energy Energy Executive Cash Balance Plan (“ECBP”), which is a noncontributory, defined benefit retirement plan that is not intended to satisfy the requirements for qualification under Section 401(a) of the Internal Revenue Code. Benefits earned under the ECBP are attributable to (i) compensation in excess of the annual compensation limit ($220,000 for 2006) under the Internal Revenue Code that applies to the determination of pay credits under the RCBP, (ii) certain deferred compensation that is not recognized by the RCBP, (iii) restoration of benefits in excess of a defined benefit plan maximum annual benefit limit ($175,000 for 2006) under the Internal Revenue Code that applies to the RCBP, and (iv) supplemental benefits granted to a particular participant. Generally, benefits earned under the RCBP and the ECBP vest upon completion of three years of service, and, with certain exceptions, vested benefits generally become payable upon termination of employment with Duke Energy.
Effective with the spin-off of Spectra Energy, the Spectra Energy Retirement Cash Balance Plan and the Spectra Energy Executive Cash Balance Plan became effective. These plans contain the same provisions as the predecessor plans sponsored by Duke Energy, and individual benefit accruals were transferred from the Duke Energy plans to the Spectra Energy plans effective with the spin-off of Spectra Energy.
Pension Choices Plan for Employees of Westcoast Energy Inc. and Duke Energy Supplemental Pension Plan
Mr. Ebel participated in the Pension Choices Plan for Employees of Westcoast Energy Inc. and Affiliated Companies (“Pension Plan”), and the Duke Energy Supplemental Executive Retirement Plan (“SERP”) in 2006, while he resided in Canada. The Pension Plan is registered under theIncome Tax Act and under thePension Benefits Act (Ontario). The executive component of the Pension Plan is a non-contributory defined benefit plan that provides a pension based on 2% of the annualized average of the executive’s highest consecutive 36 months salary and bonus multiplied by the executives’ years of service while located in Canada. The Income Tax Act imposes maximum restrictions on the amount of benefits that can be paid from a registered pension plan. The SERP is primarily intended to restore benefits under the Pension Plan to the level that would be available in accordance with the benefit formulas under the Pension Plan if such restrictions were not applicable. SERP benefits are paid from the general revenues of the Company in a lump sum. Effective with the spin-off of Spectra Energy, Mr. Ebel will participate in the Spectra RCBP, and his active participation in the Pension Plan will be suspended, although compensation (but not additional service) with Spectra will be used in the calculation of his Pension Plan benefit. Also effective with the spin-off, the Spectra Energy Supplemental Executive Retirement Plan became effective and contains the same provisions as the predecessor SERP sponsored by Duke. Mr. Ebel’s benefit accruals related to the Duke SERP were transferred to the Spectra SERP effective with the spin-off.
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The following table provides information related to each plan that provides for payments or other benefits at, following or in connection with retirement, determined as of September 30, 2006.
PENSION BENEFITS
| Name | Plan Name | Number of Years Credited Service (#) | Present ($)(1) | Payments ($) | ||||
Paul M. Anderson | Duke Energy Retirement Cash Balance Plan | 24.41 | $675,207 | $0 | ||||
Fred J. Fowler | Duke Energy Retirement Cash Balance Plan | 21.75 | $599,458 | $0 | ||||
Fred J. Fowler | Duke Energy Executive Cash Balance Plan | 21.75 | $1,881,569 | $0 | ||||
Gregory L. Ebel | Duke Energy Retirement Cash Balance Plan | 8.75 | $32,587 | $0 | ||||
Gregory L. Ebel | Duke Energy Executive Cash Balance Plan | 8.75 | $7,104 | $0 | ||||
Gregory L. Ebel | Pension Choices Plan for Employees of Westcoast Energy Inc. | 6.23 | $101,856 | $0 | ||||
Gregory L. Ebel | Duke Energy Supplemental Pension Plan | 6.23 | $315,926 | $0 | ||||
Martha B. Wyrsch | Duke Energy Retirement Cash Balance Plan | 7.08 | $114,343 | $0 | ||||
Martha B. Wyrsch | Duke Energy Executive Cash Balance Plan | 7.08 | $249,182 | $0 | ||||
Alan N. Harris | Duke Energy Retirement Cash Balance Plan | 23.87 | $275,162 | $0 | ||||
Alan N. Harris | Duke Energy Executive Cash Balance Plan | 23.87 | $125,598 | $0 | ||||
William S. Garner, Jr. | Duke Energy Retirement Cash Balance Plan | 0.56 | $9,346 | $0 | ||||
William S. Garner, Jr. | Duke Energy Executive Cash Balance Plan | 0.56 | $195 | $0 |
| (1) | For Mr. Ebel and Mr. Harris, present values represent the discounted present value of future payments to which they are entitled under the plans listed. For all other individuals listed, the amounts reflect actual cash balances accrued under the plans listed. |
Duke Energy Executive Savings Plan
Under the Duke Energy Executive Savings Plan, participants can elect to defer a portion of their base salary, short-term incentive compensation and long-term incentive compensation (other than stock options). Participants also receive a company matching contribution in excess of the contribution limits prescribed by the IRS under the Duke Energy Corporation Retirement Savings Plan. In general, payments are made following termination of employment or death in the form of a lump sum or installments, as selected by the participant. Participants may request an accelerated distribution upon an “unforeseeable emergency.” In general, participants may direct the deemed investment of base salary deferrals, short-term incentive deferrals and matching contributions among investments options available under the Duke Energy Retirement Savings Plan, including in a Duke Energy Common Stock Fund. Participants may change their investment elections on a daily basis. Deferrals of equity awards are credited with earnings and losses based on the performance of the Duke Energy Common Stock Fund. The benefits payable under the plan are unfunded and subject to the claims of Duke Energy’s creditors.
Effective with the spin-off of Spectra Energy, the Spectra Energy Executive Savings Plan and the Spectra Energy Retirement Savings Plan became effective. These plans contain the same provisions as the predecessor plans sponsored by Duke Energy, and individual benefit accruals were transferred from the Duke Energy plans to the Spectra Energy plans effective with the spin-off of Spectra Energy. Participants received credit for investment in 0.5 of a share of Spectra Energy common stock for each share of Duke Energy common stock held in the Duke Energy Common Stock Fund.
Pan Energy Key Executive Deferral Plan
Under the Panhandle Energy Eastern Corporation Key Executive Deferral Compensation Plan, participants could elect to defer a portion of their base salary and short-term incentive compensation in excess of the contributions permitted by the Internal Revenue Code under the Employees’ Savings Plan of Panhandle Eastern Corporation and Participating Affiliates. Participants also could receive employer matching contributions in
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excess of the contribution limits prescribed by the Internal Revenue Code under the Employees’ Savings Plan of Panhandle Eastern Corporation. This is a frozen plan assumed by Spectra Energy. In general, payments are made at such time as are set forth on the distribution election of the participant prior to deferral. Interest is credited on amounts deferred under the plan for a particular calendar year at a rate based on the Moody’s Seasoned Baa Corporate Bond Yield Index.
Texas Eastern Corp Deferred Income Program
Under the Texas Eastern Deferred Income Program, participants could elect to defer a portion of their base salary and short-term incentive compensation. In general, payments are made after a specified date and following termination of employment or death in the form of a lump sum or installments. Amounts credited to the Plan are credited with interest at varying rates depending upon the year of deferral and age at termination of employment. This is a frozen plan assumed by Spectra Energy.
NONQUALIFIED DEFERRED COMPENSATION
| Name | Executive
($)(1) | Registrant
($)(2) | Aggregate
($) (3) | Aggregate
($) | Aggregate
($) | |||||
Paul M. Anderson Executive Deferral Plan | $0 | $0 | $0 | $97,758 | $0 | |||||
Paul M. Anderson Deferred Income Program | $0 | $0 | $146,360 | $0 | $878,158 | |||||
Fred J. Fowler Savings Plan | $1,734,928 | $96,480 | $928,277 | $0 | $6,451,624 | |||||
Gregory L. Ebel Savings Plan | $0 | $0 | $3,419 | $0 | $64,078 | |||||
Martha B. Wyrsch Savings Plan | $100,318 | $41,960 | $169,646 | $0 | $1,312,990 | |||||
Alan N. Harris Savings Plan | $31,128 | $14,340 | $42,016 | $0 | $295,000 | |||||
William S. Garner, Jr Savings Plan | $3,333 | $0 | $198 | $0 | $3,531 |
| (1) | Includes $75,550, $52,750, $17,700 and $3,333 of salary deferrals credited to the plan in 2006 on behalf of Mr. Fowler, Ms. Wyrsch and Messrs. Harris and Garner, respectively, which are included in the salary column of the Summary Compensation Table. |
| (2) | Reflects make-whole matching contribution credits made in 2006 under the Duke Energy Corporation Executive Savings Plan with respect to elective salary deferrals made by executives during 2005. See footnote 5 to the “Summary Compensation Table” for the amount of make-whole matching contribution credits made to the Duke Energy Corporation Executive Savings Plan in 2007 with respect to elective salary deferrals made by executives during 2006. |
| (3) | Includes $59,048 of above-market interest as reported for Mr. Anderson in the Summary Compensation Table. |
Potential Payments Upon Termination of Employment or Change in Control
Under certain circumstances, each Spectra Energy named executive officer would be entitled to compensation in the event his or her employment terminates upon a change in control pursuant to agreements that were executed in connection with the spin-off of Spectra Energy. The amount of the compensation is contingent upon a variety of factors, including the circumstances under which he or she terminates employment. The relevant agreements that the Spectra Energy named executive officers entered into with Spectra Energy are described below, followed by a table that quantifies the amount that would become payable to each Spectra Energy named executive officer as a result of his or her termination of employment.
The amounts shown assume that such termination was effective as of December 31, 2006 and are merely estimates of the amounts that would be paid out to the Spectra Energy named executive officers upon their termination. In calculating the amounts shown, it was assumed that the change of control agreements were
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entered into as of such date. The actual amounts to be paid out can only be determined at the time of such Spectra Energy named executive officer’s termination of employment.
The change of control agreements have an initial term of two years, after which the agreements automatically extend, unless six months prior written notice is provided, from the first date of each month for one additional month.
The change in control agreements provide for payments and benefits to the executive in the event of termination of employment within two years after a “change in control” of Spectra Energy, other than: 1) by Spectra Energy for “cause”; 2) by reason of death or disability; or 3) of the executive for other than “good reason” (each such term as defined in the agreements) as follows: (1) a lump-sum cash payment equal to a pro-rata amount of the executive’s target bonus for the year in which the termination occurs; (2) a lump-sum cash payment equal to two times the sum of the executive’s annual base salary and target annual bonus opportunity in effect immediately prior to termination or, if higher, in effect immediately prior to the first occurrence of an event or circumstance constituting “good reason”; (3) continued medical, dental and basic life insurance coverage for a two-year period (or a lump sum cash payment of equivalent value); and (4) a lump-sum cash payment representing the amount Spectra Energy would have allocated or contributed to the executive’s qualified and nonqualified defined benefit pension plan and defined contribution savings plan accounts during the two years following the termination date, plus the unvested portion, if any, of the executive’s accounts as of the date of termination that would have vested during such two year period. In addition, the agreements provide for continued vesting of long-term incentive awards, but excluding restricted stock, for two additional years. If the executive would have become eligible for retirement at mandatory retirement age within the two-year period following termination, the two times multiple or two year period mentioned above will be reduced to the period from the termination date to the executive’s mandatory retirement date.
Under the change in control agreements, each Spectra Energy named executive officer also is entitled to reimbursement of up to $50,000 for the cost of certain legal fees incurred in connection with claims under the agreements. In the event that any of the payments or benefits provided for in the change in control agreement otherwise would constitute an “excess parachute payment” (as defined in Section 280G of the Internal Revenue Code), the amount of payments or benefits would be reduced to the maximum level that would not result in excise tax under Section 4999 of the Internal Revenue Code if such reduction would cause the executive to retain an after-tax amount in excess of what would be retained if no reduction were made. In the event a named executive officer becomes entitled to payments and benefits under a change in control agreement, he or she would be subject to a one-year noncompetition and nonsolicitation provision from the date of termination, in addition to certain confidentiality and cooperation provisions.
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The following table summarizes the consequences under Duke Energy’s long-term incentive award agreements, without giving effect to the change in control agreements described above, that would occur in the event of the termination of employment of a Spectra Energy named executive officer.
| Event | Consequences | |
Voluntary termination or involuntary termination (retirement eligible) | Phantom Shares – continue to vest
Performance Shares – prorated portion of award vests based on actual performance
Options – continue to vest | |
Voluntary termination (not retirement eligible) | Phantom Shares, Performance Shares and Options – the executive’s right to unvested portion of award terminates immediately | |
Involuntary termination (not retirement eligible) | Phantom Shares – prorated portion of award vests
Performance Shares – prorated portion of award vests based on actual performance
Options – the executive’s right to unvested shares terminates immediately | |
Involuntary termination after a Change in Control | Phantom Shares – immediate vesting
Performance Shares – see impact of Change in Control below
Options – see impact of Change in Control below | |
Death or Disability (not retirement eligible) | Phantom Shares – prorated portion of award vests
Performance Shares – prorated portion of award vests based on actual performance
Options – previously vested options are exercisable for 36 months | |
Change in Control | Phantom Shares – no impact absent termination of employment
Performance Shares – prorated portion of award vests based on target performance
Options – immediate vesting |
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POTENTIAL PAYMENTS UPON TERMINATION OF EMPLOYMENT OR A CHANGE IN CONTROL (“CIC”)
| Name and Triggering Event(1) | Cash Severance Payment ($) (2) | Incremental Retirement Plan Benefit ($) (3) | Welfare and Similar Benefits ($) (4) | Stock Awards ($) (5) (6) | Option Awards ($) (7) | |||||
Paul M. Anderson | ||||||||||
| • Voluntary termination or involuntary termination with cause | 0 | 0 | 595,889 | 0 | 0 | |||||
| • Involuntary termination without cause | 0 | 0 | 595,889 | 0 | 0 | |||||
| • Involuntary or good reason termination after a CIC | 0 | 0 | 595,889 | 0 | 0+ | |||||
| • Death | 0 | 0 | 595,889 | 0 | 0 | |||||
| • Disability | 0 | 0 | 595,889 | 0 | 0 | |||||
| Fred J. Fowler | ||||||||||
| • Voluntary termination or involuntary termination with cause | 0 | 0 | 0 | 4,265,371 | 976,860 | |||||
| • Involuntary termination without cause | 0 | 0 | 0 | 5,800,064 | 976,860 | |||||
| • Involuntary or good reason termination after a CIC | 2,870,885 | 480,130 | 20,644 | 5,800,064 | 976,860 | |||||
| • Death | 0 | 0 | 0 | 1,936,226 | 976,860 | |||||
| • Disability | 0 | 0 | 0 | 1,936,226 | 976,860 | |||||
| Gregory L. Ebel | ||||||||||
| • Voluntary termination or involuntary termination with cause | 0 | 0 | 0 | 0 | 0 | |||||
| • Involuntary termination without cause | 0 | 0 | 0 | 380,950 | 0 | |||||
| • Involuntary or good reason termination after a CIC | 828,658 | 108,091 | 29,945 | 651,832 | 41,796 | |||||
| • Death | 0 | 0 | 0 | 380,950 | 0 | |||||
| • Disability | 0 | 0 | 0 | 380,950 | 0 | |||||
| Martha B. Wyrsch | ||||||||||
| • Voluntary termination or involuntary termination with cause | 0 | 0 | 0 | 0 | 0 | |||||
| • Involuntary termination without cause | 0 | 0 | 0 | 1,058,914 | 0 | |||||
| • Involuntary or good reason termination after a CIC | 2,052,000 | 286,640 | 18,124 | 2,511,101 | 174,960 | |||||
| • Death | 0 | 0 | 0 | 1,058,914 | 0 | |||||
| • Disability | 0 | 0 | 0 | 1,058,914 | 0 | |||||
| Alan N. Harris | ||||||||||
| • Voluntary termination or involuntary termination with cause | 0 | 0 | 0 | 0 | 0 | |||||
| • Involuntary termination without cause | 0 | 0 | 0 | 76,122 | 0 | |||||
| • Involuntary or good reason termination after a CIC | 884,988 | 131,711 | 29,956 | 822,203 | 88,346 | |||||
| • Death | 0 | 0 | 0 | 408,222 | 0 | |||||
| • Disability | 0 | 0 | 0 | 408,222 | 0 | |||||
| William S. Garner, Jr. | ||||||||||
| • Voluntary termination or involuntary termination with cause | 0 | 0 | 0 | 0 | 0 | |||||
| • Involuntary termination without cause | 0 | 0 | 0 | 0 | 0 | |||||
| • Involuntary or good reason termination after a CIC | 750,024 | 103,750 | 30,746 | 303,281 | 0 | |||||
| • Death | 0 | 0 | 0 | 166,050 | 0 | |||||
| • Disability | 0 | 0 | 0 | 166,050 | 0 |
(1) | On January 1, 2007, all individuals terminated employment with Duke Energy to become employed by Spectra Energy. Any employment agreements in place at Duke Energy were terminated as of December 31, 2006. Amounts in the above table represent obligations of Spectra Energy under agreements currently in place at Spectra Energy, and valued as if they were in place on December 31, 2006. |
(2) | Amounts listed under “Cash Severance Payment” are payable under the terms of the named executive officer’s change in control agreement. The severance benefits set forth above do not include accrued salary and bonus payments earned through December 31, 2006; however such amounts are reflected in the Summary Compensation Table above. |
(3) | Pursuant to the Change in Control Agreements of Messrs. Fowler and Ebel, Ms. Wyrsch and Messrs. Harris and Garner amounts listed under “Incremental Retirement Plan Benefit” represent the additional amounts that would be credited in respect of the Spectra Energy Retirement Cash Balance Plan, Spectra Energy Executive Cash Balance Plan, Spectra Energy Retirement Savings Plan and the Spectra Energy Executive Savings Plan in the event the named executive officer continued to be employed by Spectra Energy, at his or her rate of base salary as in effect on December 31, 2006, for two additional years. |
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(4) | Amounts listed under “Welfare and Other Benefits” include: (a) accrued vacation; (b) the amount that would be paid to each named executive officer who has entered into a Change in Control Agreement in lieu of providing continued welfare benefits for 24 months, and (c) amounts paid to reimburse Mr. Anderson for a loss on the sale of his principal residence, plus a tax gross-up on such amount. |
(5) | The amounts listed under “Stock Awards” do not include amounts attributable to the phantom shares and performance shares that vested on December 31, 2006; such amounts are included in the Option Exercises and Stock Vested Table above. |
(6) | The amounts listed under “Stock Awards” do not include amounts attributable to performance shares that, upon applicable termination events, are pro-rated based on service from the grant date to December 31, 2006 and vest subject to a performance determination at the end of the performance period. The amounts listed would be the result of the acceleration of the vesting of previously awarded stock as a result of a change in control. |
(7) | The amounts listed under “Option Awards” consist of only those options for which (i) vesting is accelerated upon the applicable termination event or (ii) vesting continues after the applicable termination event (i.e., due to the executives being retirement eligible). As of December 31, 2006, and without regard to any acceleration of vesting that would otherwise occur upon a triggering event, the vested options of Messrs. Anderson, Fowler and Ebel, Ms. Wyrsch and Messrs. Harris and Garner were 1,100,000; 972,850; 29,318; 140,700; 42,550 and 0, respectively. |
The amounts listed in the preceding table have been determined based on a variety of assumptions, and the actual amounts to be paid out can only be determined at the time of each Spectra Energy named executive officer’s termination of employment. The amounts described in the table do not include compensation to which each Spectra Energy named executive officer would be entitled without regard to his or her termination of employment, including (i) base salary and short-term incentives that have been earned but not yet paid, and (ii) amounts that have been earned, but not yet paid, under the terms of the plans listed under the “Pension Benefits” and “Nonqualified Deferred Compensation” tables.
The amounts shown above do not reflect the fact that, with respect to each Spectra Energy named executive officer who is covered by a change in control agreement, in the event that payments to such executive in connection with a change in control otherwise would result in an excise tax under Section 4999 of the Internal Revenue Code of 1986, as amended, under certain circumstances such amounts would be reduced to the extent necessary so that such tax would not apply.
The amounts shown above with respect to outstanding Duke Energy stock awards and option awards were calculated based on a variety of assumptions, including the following: (i) the Spectra Energy named executive officer terminated employment on the last day of 2006; (ii) a stock price for Duke Energy common stock equal to $33.21, which was the closing price on December 29, 2006; (iii) the continuation of Duke Energy’s dividend at the rate in effect on December 31, 2006; and (iv) performance at the target level with respect to performance shares. Additionally, the amounts listed above with respect to Mr. Fowler reflect the fact that, upon termination for any reason, he would receive the full value of all unvested phantom shares and the dividends that would be paid on such shares for the remainder of the original vesting period, in accordance with the terms of the awards, because he has attained retirement age.
Under the change of control agreements that became effective for all Spectra Energy named executive officers effective January 2, 2007, other than as described below, the occurrence of a change in control of Spectra Energy would not trigger the payment of benefits to the named executive officers absent a termination of employment. If a change in control of Duke Energy occurred on December 31, 2006, the outstanding performance shares awards would be paid out on a prorated basis assuming target performance. As of December 31, 2006, the prorated performance shares that would be paid as a result of these accelerated vesting provisions would have had a value of $0, $1,501,208, $448,919, $626,102, $182,247, and $35,277 for Messrs. Anderson, Fowler and Ebel, Ms. Wyrsch and Messrs. Harris and Garner, respectively. In addition, options with a December 31, 2006 intrinsic value (the excess of the market price of Duke Energy common stock over the exercise prices) of $0, $976,860, $41,796, $174,960, $88,346 and $0 for Messrs. Anderson, Fowler and Ebel, Ms. Wyrsch and Messrs. Harris and Garner, respectively, would have become vested upon a change in control.
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Directors’ Compensation
Some members of Spectra Energy’s Board of Directors served as directors of Spectra Energy prior to its spin-off from Duke Energy in January of 2007. However, none of these directors received compensation for his or her services as a director of Spectra Energy in 2006. Effective with the January 2007 spin-off from Duke Energy, Spectra Energy became an independent corporate entity and, concurrently, the following new compensation program became effective for non-employee, or outside, directors.
Type of Fee | Fee (Other Than for Meetings) | Meeting Fees | ||||||
| In-Person Attendance at Meetings Held in Conjunction With a Regular Board Meeting | In-Person Meetings a Regular Board | Telephonic Participation in Meetings | ||||||
Annual Board Retainer (Cash) | $50,000 | |||||||
Annual Board Retainer (Stock) | $75,000 | |||||||
Board Meeting Fees | $2,000 | $2,500 | $2,000 | |||||
Annual Audit Committee Chair Retainer | $20,000 | |||||||
Annual Chair Retainer (Other Committees) | $8,500 | |||||||
Audit Committee Meeting Fees | $3,000 | $2,500 | $2,000 | |||||
Other Committee Meeting Fees | $2,000 | $2,500 | $2,000 | |||||
Annual Stock Retainer for 2007. In 2007, each director will receive a grant of a number of shares of Spectra Energy stock equal to $75,000 divided by the closing price of Spectra Energy’s common stock on the New York Stock Exchange on the date of grant.
Compensation of the Chairman of the Board. Prior to the spin-off, the Duke Energy Compensation Committee determined an annual amount of $500,000 to be an appropriate level of compensation for the Chairman of the Board, given the significant role Mr. Anderson is expected to play in setting the strategic direction of Spectra Energy. Further, it was determined that the compensation paid to Mr. Anderson in his role as Chairman would be through stock awards delivered in the same form as annual grants to Spectra Energy’s leadership employees. Under this arrangement, Mr. Anderson does not receive any cash retainer or meeting fees while fulfilling his role as Chairman but is eligible to participate in the Directors’ deferral plan and Matching Gifts Program described below.
On February 27, 2007 stock awards were granted to leadership employees as follows: (1) 50% of executive’s grant value was delivered in the form of nonqualified stock options that vest ratably over a three-year period and, a term of ten years and have an exercise price equal to the closing price of Spectra Energy shares on the date of grant; and (2) 50% of the executive’s grant value was delivered in the form of phantom stock units that cliff vest on the third anniversary of the date of the award with dividend equivalents accumulated and paid when the underlying phantom stock units vest. Accordingly, on February 27, 2007 Mr. Anderson was awarded64,400 nonqualified stock options valued at $250,000 and11,100 phantom stock units (with tandem dividend equivalents) valued at $250,000.
Deferral Plans and Stock Purchases. Programs allowing deferral and stock purchase opportunities comparable to programs available at Duke Energy were made available to outside directors of Spectra Energy, and account balances of Spectra Energy’s outside directors who were Duke Energy outside directors have been transferred to plans managed by Spectra Energy on the directors’ behalf. Generally, directors may elect to receive all or a portion of their annual compensation, consisting of retainers and attendance fees, on a current basis, or defer such compensation under the Spectra Energy Directors’ Savings Plan. Up to 50% of annual cash compensation may also be received on a current basis in the form of Spectra Energy common stock. Deferred amounts are credited to an unfunded account for the director’s benefit, the balance of which is adjusted for the
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performance of phantom investment options, including the Spectra Energy common stock fund, as elected by the director. Each outside director will receive deferred amounts credited to his or her account generally following termination of his or her service on the Spectra Energy Board of Directors, in accordance with his or her distribution elections
Charitable Giving Program. Spectra Energy’s outside directors who participated in the frozen Duke Energy Directors’ Charitable Giving Program continue to be eligible for a comparable benefit. Under this program, Spectra Energy will make, upon the director’s death, donations of up to $1,000,000 to charitable organizations selected by the director. An outside director may request that Spectra Energy make donations under this program during the director’s lifetime, in which case the maximum donation will be reduced on an actuarially-determined net present value basis. In addition, Spectra Energy maintains the Spectra Energy Matching Gifts Program under which outside directors are eligible for matching contributions of up to $5,000 per director per calendar year to qualifying institutions.
Expense Reimbursement and Insurance. Spectra Energy reimburses outside directors for expenses reasonably incurred in connection with attendance and participation at Board and Committee meetings and special functions. Spectra Energy chose not to continue Duke Energy’s practice of providing travel insurance to outside directors.
Stock Ownership Guidelines. Outside directors are subject to stock ownership guidelines which establish a target level of ownership of Spectra Energy common stock (or common stock equivalents) of 4,000 shares. However, the ownership guideline adopted for Mr. Anderson, Chairman of the Board, is 50,000 shares.
Compensation Committee Interlocks and Insider Participation
With the exception of Mr. Fowler and Ms. Wyrsch, none of the executive officers serve as a director of Spectra Energy and Mr. Fowler and Ms. Wyrsch do not serve on the Compensation Committee. None of the executive officers of Spectra Energy serve, or during 2006 served, as a member of the compensation committee of any entity that has one or more executive officers serving on Spectra Energy’s Compensation Committee.
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ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table indicates the amount of Spectra Energy common stock beneficially owned by the directors, the executive officers listed in the Summary Compensation Table under “Executive Compensation” below (referred to as the Named Executive Officers), and by all directors and executive officers as a group as of March 14, 2007.
Name or Identity of Group | Total Shares Beneficially Owned (1) | Percent of Class | ||
Austin Adams | 0 | * | ||
Roger Agnelli | 2,297 | * | ||
Paul M. Anderson | 884,527 | * | ||
Keith A. Crane | 0 | * | ||
Greg L. Ebel | 21,668 | * | ||
William T. Esrey | 33,556 | * | ||
Fred J. Fowler | 696,984 | * | ||
William S. Garner | 1,302 | * | ||
Peter B. Hamilton | 0 | * | ||
Sabra L. Harrington | 10,091 | * | ||
Alan N. Harris | 35,687 | * | ||
Dennis R. Hendrix | 126,221 | * | ||
Michael E. J. Phelps | 6,487 | * | ||
Martha B. Wyrsch | 105,090 | * | ||
Directors and executive officers as a group | 1,923,910 | * |
| * | Represents less than 1%. |
| (1) | Includes the following number of shares with respect to which directors and executive officers have the right to acquire beneficial ownership within 60 days of March 14, 2007: R. Agnelli – 1,354; P.M. Anderson – 550,000; G.L. Ebel – 16,087; W.T. Esrey – 12,942; F.J. Fowler – 579,158; W.S. Garner – 1,140; S.L. Harrington – 5,639; A.N. Harris – 25,618; D.R. Hendrix – 5,354; M.E. Phelps – 5,233; M.B. Wyrsch – 79,444. The amounts set forth in the table for Messrs. Adams, Agnelli, Esrey, Hamilton, Hendrix and Phelps do not include shares of common stock which will be granted within 60 days of March 14, 2007 for the 2007 annual stock retainer. |
The following table lists the beneficial owners of 5% or more of Spectra Energy’s outstanding shares of common stock as of March 14, 2007. This information is based on the most recently available reports filed with the SEC and provided to us by the company listed.
| Shares of common stock | |||||
Name and Address of Beneficial Owner | Beneficially Owned | Percentage | |||
State Street Bank and Trust Company 225 Franklin Street, Boston, Ma. 02110 | 48,229,210 | 7.6 | % | ||
(1) According to the Schedule 13G filed on March 2, 2007 by State Street Bank and Trust Company, these shares are beneficially owned by its clients, and State Street Bank and Trust Company has sole voting power with respect to 21,922,149 shares, shared voting power with respect to 26,307,061 shares, and shared dispositive power with respect to all of these shares.
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The following table shows information, as of December 31, 2006, about securities to be issued upon exercise of outstanding options, warrants and rights under Spectra Energy’s equity compensation plans, along with the weighted-average exercise price of the outstanding options, warrants and rights and the number of securities remaining available for future issuance under the plans. As of December 31, 2006, Spectra Energy had adopted the Spectra Energy Corp 2007 Long-Term Incentive Plan and reserved shares of Spectra Energy common stock for issuance thereunder.
Plan Category
| Number of securities to be (a) | Weighted-average (b) | Number of securities remaining available under equity compensation plans (excluding securities reflected in column (a)) (c) | ||||
Equity compensation plans approved by security holders | -0- | N/A | 30,000,000 | 1 | |||
Equity compensation plans not approved by security holders | -0- | N/A | -0- | ||||
Total | -0- | N/A | 30,000,000 | ||||
1 | Represents shares available for issuance for awards of restricted stock, performance shares or phantom stock under the Spectra Energy Corp 2007 Long-Term Incentive Plan. The amount set forth in the table does not include an indeterminate number of awards permitted to be made under the Spectra Energy Corp 2007 Long-Term Incentive Plan in connection with the equitable adjustment of outstanding Duke Energy awards in connection with the spin-off of Spectra Energy. |
| ITEM 13. | Certain Relationships and Related Transactions, and Director Independence |
Certain Relationships and Related Transactions
Agreements with Duke Energy
Before Spectra Energy’s separation from Duke Energy, it entered into a Separation and Distribution Agreement and several other agreements with Duke Energy to effect the separation and provide a framework for Spectra Energy’s relationships with Duke Energy after the separation. These agreements govern the relationship between Spectra Energy and Duke Energy following the completion of the separation and provide for the allocation between the parties, of certain of Duke Energy’s assets, liabilities and obligations (including employee benefits and tax-related assets and liabilities) attributable to periods prior to, at and after Spectra Energy’s separation from Duke Energy. In addition to the Separation and Distribution Agreement (which contains many of the key provisions related to Spectra Energy’s separation from Duke Energy), these agreements include the Transition Services Agreement, the Tax Matters Agreement and the Employee Matters Agreement. The descriptions set forth below are of the material provisions of these agreements that continue to have effect following the completion of the separation of Spectra Energy from Duke Energy.
Separation and Distribution Agreement
The Separation and Distribution Agreement sets forth agreements that govern certain aspects of Spectra Energy’s relationships with Duke Energy following the completion of the spin-off transaction. This agreement identifies assets that were transferred, liabilities that were assumed and contracts that were assigned to each of Spectra Energy and Duke Energy as part of the separation of Duke Energy into two companies. The Separation and Distribution Agreement provides for the formation of a contingent claim committee, which has the responsibility for determining whether any newly discovered asset or liability is an asset or liability of Spectra Energy or Duke Energy, or is an unallocated asset or unallocated liability, one-third of which will be assigned to
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Spectra Energy and two-thirds of which will be assigned to Duke Energy. The contingent claim committee is comprised of one representative each from Duke Energy and Spectra Energy. Resolution of a matter submitted to the contingent claim committee requires the unanimous approval of the representatives. In addition, the Separation and Distribution Agreement provides for cross-indemnities principally designed to place financial responsibility for the obligations and liabilities of Spectra Energy’s business with Spectra Energy and financial responsibility for the obligations and liabilities of Duke Energy’s business with Duke Energy.
Transition Services Agreement
Under the Transition Services Agreement, Spectra Energy and Duke Energy agreed to provide certain services to each other for a specified period following the spin-off of Spectra Energy. The services provided under this agreement include services regarding business continuity and management, facilities management, data archiving, including services relating to human resources and employee benefits, payroll, financial systems management, treasury and cash management, accounts payable services, telecommunications services and information technology services.
The recipient of any services generally pays an agreed upon service charge and reimburses the provider any out-of-pocket expenses, including the cost of any third-party consents required. The charges for these services are billed at cost to the company receiving the services with an increase by a specified percentage for services provided for 180 days after the separation. The Transitional Services Agreement generally requires the services to be provided until December 31, 2007.
Tax Matters Agreement
The Tax Matters Agreement generally governs Spectra Energy’s and Duke Energy’s respective rights, responsibilities and obligations with respect to taxes, including ordinary course of business taxes and taxes, if any, incurred as a result of any failure of the spin-off of Spectra Energy to qualify as a tax-free distribution for U.S. federal income tax purposes. Under the Tax Matters Agreement, Spectra Energy is generally responsible for the payment of all income and non-income taxes attributable to its operations, and the operations of its direct and indirect subsidiaries, whether or not such tax liability is reflected on a consolidated or combined tax return filed by Duke Energy. No fees will be paid by either party to the other party under the Tax Matters Agreement.
Notwithstanding the foregoing, under the Tax Matters Agreement, Spectra Energy is generally responsible for any taxes imposed on Duke Energy that arise from the failure of the spin-off of Spectra Energy to qualify as a tax-free distribution for U.S. federal income tax purposes, to the extent that such failure to qualify is attributable to actions, events or transactions relating to Spectra Energy’s stock, assets or business, or a breach of the relevant representations or covenants made by Spectra Energy in the Tax Matters Agreement. In addition, Spectra Energy is generally responsible for one-third of any taxes that arise from the failure of the spin-off of Spectra Energy to qualify as a tax-free distribution for U.S. federal income tax purposes, if such failure is for any reason for which neither Spectra Energy nor Duke Energy is responsible. The Tax Matters Agreement also imposes restrictions on Spectra Energy’s and Duke Energy’s ability to engage in certain actions following Spectra Energy’s separation from Duke Energy and to set forth the respective obligations among Spectra Energy and Duke Energy with respect to filing of tax returns, the administration of tax contests, assistance and cooperation and other matters.
Employee Matters Agreement
The Employee Matters Agreement governs the compensation and employee benefit obligations with respect to Spectra Energy’s current and former employees. The Employee Matters Agreement allocates liabilities and responsibilities relating to employee compensation and benefits plans and programs and other related matters in connection with the spin-off including the treatment of outstanding Duke Energy equity awards, certain outstanding annual and long-term incentive awards, existing deferred compensation obligations and certain retirement and welfare benefit obligations.
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Index to Financial Statements
Transactions with Related Persons
Spectra Energy recognizes that related-person transactions can present potential or actual conflicts of interest and it is Spectra Energy’s preference that related-person transactions are avoided as a general matter. Nevertheless, Spectra Energy recognizes that there are situations, including certain transactions negotiated on an arm’s length basis, where related-person transactions may be in, or may not be inconsistent with, the best interests of Spectra Energy and its shareholders. Therefore, Spectra Energy has procedures for the approval, ratification and review of on-going related-person transactions. The Audit Committee of the Board of Directors is charged with the responsibility to review, ratify or approve, as necessary, any related-person transactions prior to the transaction being entered into, or ratify any related-person transactions that have been previously approved, in which a director, executive officer or owner of 5% or more of common stock or immediate family member of any such person has a material interest, and which transaction is in an amount equal to or in excess of $120,000, either individually or in the aggregate of several transactions during any calendar year. Based on our review of on-going related-person transactions, we have not entered into and do not currently propose to enter into any transactions with related persons required to be disclosed under federal securities laws.
Independence of Directors
The Board of Directors may determine a director to be independent if the Board has affirmatively determined that the director has no material relationship with Spectra Energy or its consolidated subsidiaries, either directly or as a shareholder, director, officer or employee of an organization that has a relationship with Spectra Energy or its subsidiaries. Independence determinations will be made on an annual basis at the time the Board of Directors approves director nominees for inclusion in the annual proxy statement and, if a director joins the Board between annual meetings, at such time.
The Board of Directors has determined that none of Mssrs. Adams, Agnelli, Esrey, Hamilton, Hendrix and Phelps, has a material relationship with Spectra Energy or its subsidiaries, and are, therefore, independent under the listing standards of the New York Stock Exchange. In reaching this conclusion, the Board of Directors considered all transactions and relationships between each director or any member of his or her immediate family and Spectra Energy and its subsidiaries.
Item 14. Principal Accounting Fees and Services.
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 Spectra Energy Capital for 2006 and 2005. Fee amounts represent an allocation to Spectra Energy Capital of total Duke Energy fees as determined by management:
Type of Fees | FY 2006 | FY 2005 | ||||
| (In millions) | ||||||
Audit Fees (a) | $ | 5.3 | $ | 14.0 | ||
Audit-Related Fees (b) | 3.0 | 3.9 | ||||
Tax Fees (c) | 0.6 | 4.9 | ||||
All Other Fees (d) | 0.1 | 0.3 | ||||
Total Fees: | $ | 9.0 | $ | 23.1 | ||
| (a) | Audit Fees are fees billed or expected to be billed by Deloitte for professional services for the audit of Spectra Energy Capital’s consolidated financial statements included in Spectra Energy Capital’s annual report on Form 10-K and review of financial statements included in Spectra Energy Capital’s quarterly reports on Form 10-Q, services that are normally provided by Deloitte in connection with statutory, regulatory or other 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 SEC filings and financing transactions. Audit Fees also includes fees billed or expected to be billed by Deloitte for professional services for the audit of Spectra Energy Capital’s internal controls under the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and related regulations. |
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Index to Financial Statements
| (b) | 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 Spectra Energy Capital’s financial statements, including assistance with acquisitions and divestitures, internal control reviews, employee benefit plan audits and general assistance with the implementation of the SEC rules pursuant to the Sarbanes-Oxley Act. |
| (c) | 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. |
| (d) | 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. |
To safeguard the continued independence of the independent auditor, the Spectra Energy Audit Committee adopted a policy that prevents Spectra Energy’s independent auditor from providing services to Spectra 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 engagements performed by the independent auditor in 2006 were approved by the Audit Committee pursuant to its pre-approval policy.
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Index to Financial Statements
PART IV
Item 15. Exhibits, Financial Statement Schedules.
(a) Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedules included in Part II of this annual report are as follows:
Spectra Energy Corp:
Report of Independent Registered Public Accounting Firm
Balance Sheet as of December 31, 2006
Notes to the Financial Statements
Spectra Energy Capital, LLC:
Report of Independent Registered Accounting Firm
Consolidated Statements of Operations for the Years Ended December 31, 2006, 2005 and 2004
Consolidated Balance Sheets as of December 31, 2006 and 2005
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004
Consolidated Statements of Member’s Equity and Comprehensive Income for the Years ended
December 31, 2006, 2005 and 2004
Notes to the Consolidated Financial Statements
Quarterly Financial Data (unaudited, included in Note 22 to the Consolidated Financial Statements)
Consolidated Financial Statement Schedule II—Valuation and Qualifying Accounts and Reserves for
the Years Ended December 31, 2006, 2005 and 2004
Separate Financial Statements of Subsidiaries not Consolidated Pursuant to Rule 3-09 of Regulation S-X:
TEPPCO Partners, L.P.:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2005 and 2004
Consolidated Statements of Income for the Years Ended December 31, 2005, 2004 and 2003
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003
Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2005, 2004 and 2003
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2005, 2004
and 2003
Notes to Consolidated Financial Statements
DCP Midstream, LLC (formerly Duke Energy Field Services, LLC):
Independent Auditors’ Report
Consolidated Balance Sheets as of December 31, 2006 and 2005
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2006 and 2005
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006 and 2005
Consolidated Statements of Members’ Equity for the Years Ended December 31, 2006 and 2005
Notes to Consolidated Financial Statements
Consolidated Financial Statement Schedule II of DCP Midstream, LLC—Consolidated Valuation and
Qualifying Accounts and Reserves for the Years Ended December 31, 2006 and 2005
All other schedules are omitted because they are not required, or because the required information is
included in the Consolidated Financial Statements or Notes.
(c) Exhibits—See Exhibit Index immediately following the DCP Midstream, LLC financial statements
referenced above.
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Index to Financial Statements
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.
Date: April 2, 2007
SPECTRA ENERGY CORP (Registrant) | ||
| By: | /S/ FRED J. FOWLER | |
Fred J. Fowler President and Chief Executive Officer | ||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
| (i) | Fred J. Fowler* |
| President and Chief Executive Officer (Principal Executive Officer and Director) |
| (ii) | Gregory L. Ebel* |
| Group Executive and Chief Financial Officer (Principal Financial Officer) |
| (iii) | Sabra L. Harrington* |
| Vice President and Controller (Principal Accounting Officer) |
| (iv) | Paul M. Anderson* |
| Chairman of the Board of Directors |
| Austin A. Adams* |
| Director |
| Roger Agnelli* |
| Director |
| William T. Esrey* |
| Director |
| Peter B. Hamilton* |
| Director |
| Dennis R. Hendrix* |
| Director |
| Michael E.J. Phelps* |
| Director |
| Martha B. Wyrsch* |
| Director |
Date: April 2, 2007
Gregory L. Ebel, by signing his name hereto, does hereby sign this document on behalf of the registrant and on behalf of each of the above-named persons previously indicated by asterisk pursuant to a power of attorney duly executed by the registrant and such persons, filed with the Securities and Exchange Commission as an exhibit hereto.
| By: | /s/ Gregory L. Ebel
| |
Gregory L. Ebel Attorney-In-Fact |
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Index to Financial Statements
CONSOLIDATED FINANCIAL STATEMENTS
OF TEPPCO PARTNERS, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| Page | ||
Consolidated Financial Statements: | ||
| F-2 | ||
Consolidated Balance Sheets as of December 31, 2005 and 2004 (as restated) | F-3 | |
| F-4 | ||
| F-5 | ||
| F-7 | ||
| F-8 | ||
| F-9 | ||
F-1
Table of Contents
Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of TEPPCO Partners, L.P.:
We have audited the accompanying consolidated balance sheets of TEPPCO Partners, L.P. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2005. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of TEPPCO Partners, L.P. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 20 to the consolidated financial statements, the Partnership has restated its consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash flows for the years ended December 31, 2004 and 2003.
/s/ KPMG LLP |
Houston, Texas
February 28, 2006, except for the effects of discontinued operations,
as discussed in Note 5, which is as of June 1, 2006
F-2
Table of Contents
Index to Financial Statements
CONSOLIDATED BALANCE SHEETS
(in thousands)
| December 31, | ||||||||
| 2005 | 2004 | |||||||
| (as restated) | ||||||||
| ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 119 | $ | 16,422 | ||||
Accounts receivable, trade (net of allowance for doubtful accounts of $250 and $112) | 803,373 | 553,628 | ||||||
Accounts receivable, related parties | 5,207 | 11,845 | ||||||
Inventories | 29,069 | 19,521 | ||||||
Other | 61,361 | 42,138 | ||||||
Total current assets | 899,129 | 643,554 | ||||||
Property, plant and equipment, at cost (net of accumulated depreciation and amortization of $474,332 and $407,670) | 1,960,068 | 1,703,702 | ||||||
Equity investments | 359,656 | 363,307 | ||||||
Intangible assets | 376,908 | 407,358 | ||||||
Goodwill | 16,944 | 16,944 | ||||||
Other assets | 67,833 | 51,419 | ||||||
Total assets | $ | 3,680,538 | $ | 3,186,284 | ||||
| LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued liabilities | $ | 800,033 | $ | 564,464 | ||||
Accounts payable, related parties | 11,836 | 24,654 | ||||||
Accrued interest | 32,840 | 32,292 | ||||||
Other accrued taxes | 16,532 | 13,309 | ||||||
Other | 75,970 | 46,593 | ||||||
Total current liabilities | 937,211 | 681,312 | ||||||
Senior Notes | 1,119,121 | 1,127,226 | ||||||
Other long-term debt | 405,900 | 353,000 | ||||||
Other liabilities and deferred credits | 16,936 | 13,643 | ||||||
Commitments and contingencies | ||||||||
Partners’ capital: | ||||||||
Accumulated other comprehensive income | 11 | — | ||||||
General partner’s interest | (61,487 | ) | (35,881 | ) | ||||
Limited partners’ interests | 1,262,846 | 1,046,984 | ||||||
Total partners’ capital | 1,201,370 | 1,011,103 | ||||||
Total liabilities and partners’ capital | $ | 3,680,538 | $ | 3,186,284 | ||||
See accompanying Notes to Consolidated Financial Statements
F-3
Table of Contents
Index to Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per Unit amounts)
| Years Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
| (as restated) | (as restated) | |||||||||||
Operating revenues: | ||||||||||||
Sales of petroleum products | $ | 8,061,808 | $ | 5,426,832 | $ | 3,766,651 | ||||||
Transportation—Refined products | 144,552 | 148,166 | 138,926 | |||||||||
Transportation—LPGs | 96,297 | 87,050 | 91,787 | |||||||||
Transportation—Crude oil | 37,614 | 37,177 | 29,057 | |||||||||
Transportation—NGLs | 43,915 | 41,204 | 39,837 | |||||||||
Gathering—Natural gas | 152,797 | 140,122 | 135,144 | |||||||||
Other | 68,051 | 67,539 | 54,430 | |||||||||
Total operating revenues | 8,605,034 | 5,948,090 | 4,255,832 | |||||||||
Costs and expenses: | ||||||||||||
Purchases of petroleum products | 7,986,438 | 5,367,027 | 3,711,207 | |||||||||
Operating, general and administrative | 218,920 | 219,909 | 198,478 | |||||||||
Operating fuel and power | 48,972 | 48,139 | 41,362 | |||||||||
Depreciation and amortization | 110,729 | 112,284 | 100,728 | |||||||||
Taxes—other than income taxes | 20,610 | 17,340 | 15,597 | |||||||||
Gains on sales of assets | (668 | ) | (1,053 | ) | (3,948 | ) | ||||||
Total costs and expenses | 8,385,001 | 5,763,646 | 4,063,424 | |||||||||
Operating income | 220,033 | 184,444 | 192,408 | |||||||||
Interest expense—net | (81,861 | ) | (72,053 | ) | (84,250 | ) | ||||||
Equity earnings | 20,094 | 22,148 | 12,874 | |||||||||
Other income—net | 1,135 | 1,320 | 748 | |||||||||
Income from continuing operations | 159,401 | 135,859 | 121,780 | |||||||||
Discontinued operations | 3,150 | 2,689 | — | |||||||||
Net income | $ | 162,551 | $ | 138,548 | $ | 121,780 | ||||||
Net Income Allocation: | ||||||||||||
Limited Partner Unitholders income from continuing operations | $ | 112,744 | $ | 96,667 | $ | 86,357 | ||||||
Limited Partner Unitholders income from discontinued operations | 2,228 | 1,913 | — | |||||||||
Total Limited Partner Unitholders net income allocation | 114,972 | 98,580 | 86,357 | |||||||||
Class B Unitholder net income allocation | — | — | 1,754 | |||||||||
General Partner income from continuing operations | 46,657 | 39,192 | 33,669 | |||||||||
General Partner income from discontinued operations | 922 | 776 | — | |||||||||
Total General Partner net income allocation | 47,579 | 39,968 | 33,669 | |||||||||
Total net income allocated | $ | 162,551 | $ | 138,548 | $ | 121,780 | ||||||
Basic and diluted net income per Limited Partner and Class B Unit: | ||||||||||||
Continuing operations | $ | 1.67 | $ | 1.53 | $ | 1.47 | ||||||
Discontinued operations | 0.04 | 0.03 | — | |||||||||
Basic and diluted net income per Limited Partner and Class B Unit | $ | 1.71 | $ | 1.56 | $ | 1.47 | ||||||
Weighted average Limited Partner and Class B Units outstanding | 67,397 | 62,999 | 59,765 | |||||||||
See accompanying Notes to Consolidated Financial Statements.
F-4
Table of Contents
Index to Financial Statements
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| Years Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
| (as restated) | (as restated) | |||||||||||
Cash flows from operating activities: | ||||||||||||
Net income | $ | 162,551 | $ | 138,548 | $ | 121,780 | ||||||
Adjustments to reconcile net income to cash provided by continuing operating activities: | ||||||||||||
Income from discontinued operations | (3,150 | ) | (2,689 | ) | — | |||||||
Depreciation and amortization | 110,729 | 112,284 | 100,728 | |||||||||
Earnings in equity investments, net of distributions | 16,991 | 25,065 | 15,129 | |||||||||
Gains on sales of assets | (668 | ) | (1,053 | ) | (3,948 | ) | ||||||
Non-cash portion of interest expense | 1,624 | (391 | ) | 4,793 | ||||||||
Increase in accounts receivable | (249,745 | ) | (181,690 | ) | (100,085 | ) | ||||||
Decrease (increase) in accounts receivable, related parties | 6,638 | (14,693 | ) | 8,788 | ||||||||
Increase in inventories | (970 | ) | (3,433 | ) | (956 | ) | ||||||
Increase in other current assets | (19,088 | ) | (9,926 | ) | (953 | ) | ||||||
Increase in accounts payable and accrued expenses | 254,251 | 186,942 | 95,540 | |||||||||
Increase (decrease) in accounts payable, related parties | (12,817 | ) | 4,360 | 7,381 | ||||||||
Other | (15,623 | ) | 10,572 | (5,773 | ) | |||||||
Net cash provided by continuing operating activities | 250,723 | 263,896 | 242,424 | |||||||||
Net cash provided by discontinued operations | 3,782 | 3,271 | — | |||||||||
Net cash provided by operating activities | 254,505 | 267,167 | 242,424 | |||||||||
Cash flows from continuing investing activities: | ||||||||||||
Proceeds from sales of assets | 510 | 1,226 | 8,531 | |||||||||
Proceeds from cash investments | — | — | 750 | |||||||||
Purchase of assets | (112,231 | ) | (3,421 | ) | (27,469 | ) | ||||||
Investment in Mont Belvieu Storage Partners, L.P. | (4,233 | ) | (21,358 | ) | (2,533 | ) | ||||||
Investment in Centennial Pipeline LLC | — | (1,500 | ) | (4,000 | ) | |||||||
Purchase of additional interest in Centennial Pipeline LLC | — | — | (20,000 | ) | ||||||||
Cash paid for linefill on assets owned | (14,408 | ) | (957 | ) | (3,070 | ) | ||||||
Capital expenditures | (220,553 | ) | (156,749 | ) | (126,707 | ) | ||||||
Net cash used in continuing investing activities | (350,915 | ) | (182,759 | ) | (174,498 | ) | ||||||
Net cash used in discontinued investing activities | — | (7,398 | ) | (13,810 | ) | |||||||
Net cash used in investing activities | (350,915 | ) | (190,157 | ) | (188,308 | ) | ||||||
Cash flows from financing activities: | ||||||||||||
Proceeds from revolving credit facility | 657,757 | 324,200 | 382,000 | |||||||||
Issuance of Limited Partner Units, net | 278,806 | — | 287,506 | |||||||||
Issuance of Senior Notes | — | — | 198,570 | |||||||||
Repayments on revolving credit facility | (604,857 | ) | (181,200 | ) | (604,000 | ) | ||||||
Repurchase and retirement of Class B Units | — | — | (113,814 | ) | ||||||||
Debt issuance costs | (498 | ) | — | (3,381 | ) | |||||||
General Partner’s contributions | — | — | 2 | |||||||||
Distributions paid | (251,101 | ) | (233,057 | ) | (202,498 | ) | ||||||
Net cash provided by (used in) financing activities | 80,107 | (90,057 | ) | (55,615 | ) | |||||||
Net decrease in cash and cash equivalents | (16,303 | ) | (13,047 | ) | (1,499 | ) | ||||||
Cash and cash equivalents at beginning of period | 16,422 | 29,469 | 30,968 | |||||||||
Cash and cash equivalents at end of period | $ | 119 | $ | 16,422 | $ | 29,469 | ||||||
See accompanying Notes to Consolidated Financial Statements
F-5
Table of Contents
Index to Financial Statements
TEPPCO PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS—(Continued)
(in thousands)
| Years Ended December 31, | |||||||||
| 2005 | 2004 | 2003 | |||||||
| (as restated) | (as restated) | ||||||||
Non-cash investing activities: | |||||||||
Net assets transferred to Mont Belvieu Storage Partners, L.P. | $ | 1,429 | $ | — | $ | 61,042 | |||
Supplemental disclosure of cash flows: | |||||||||
Cash paid for interest (net of amounts capitalized) | $ | 82,315 | $ | 77,510 | $ | 79,930 | |||
See accompanying Notes to Consolidated Financial Statements.
F-6
Table of Contents
Index to Financial Statements
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands, except Unit amounts)
| Outstanding Limited Partner Units | General Partner’s Interest | Limited Partners’ Interests | Accumulated Other Comprehensive (Loss) Income | Total | ||||||||||||||
Partners’ capital at December 31, 2002 (as restated) | 53,809,597 | $ | 12,104 | $ | 897,400 | $ | (20,055 | ) | $ | 889,449 | ||||||||
Issuance of Limited Partner Units, net | 9,101,650 | — | 285,461 | — | 285,461 | |||||||||||||
Retirement of Class B units | — | — | (11,175 | ) | — | (11,175 | ) | |||||||||||
Net income on cash flow hedge | — | — | — | 16,164 | 16,164 | |||||||||||||
Reclassification due to discontinued portion of cash flow hedge | — | — | — | 989 | 989 | |||||||||||||
2003 net income allocation | — | 33,669 | 86,357 | — | 120,026 | |||||||||||||
2003 cash distributions | — | (54,725 | ) | (145,427 | ) | — | (200,152 | ) | ||||||||||
Issuance of Limited Partner Units upon exercise of options | 87,307 | 2 | 2,045 | — | 2,047 | |||||||||||||
Partners’ capital at December 31, 2003 (as restated) | 62,998,554 | (8,950 | ) | 1,114,661 | (2,902 | ) | 1,102,809 | |||||||||||
Adjustments to issuance of Limited Partner Units, net | — | — | (99 | ) | — | (99 | ) | |||||||||||
Net income on cash flow hedge | — | — | — | 2,902 | 2,902 | |||||||||||||
2004 net income allocation | — | 39,968 | 98,580 | — | 138,548 | |||||||||||||
2004 cash distributions | — | (66,899 | ) | (166,158 | ) | — | (233,057 | ) | ||||||||||
Partners’ capital at December 31, 2004 (as restated) | 62,998,554 | (35,881 | ) | 1,046,984 | — | 1,011,103 | ||||||||||||
Issuance of Limited Partner Units, net | 6,965,000 | — | 278,806 | — | 278,806 | |||||||||||||
Changes in fair values of crude oil hedges | — | — | — | 11 | 11 | |||||||||||||
2005 net income allocation | — | 47,579 | 114,972 | — | 162,551 | |||||||||||||
2005 cash distributions | — | (73,185 | ) | (177,916 | ) | — | (251,101 | ) | ||||||||||
Partners’ capital at December 31, 2005 | 69,963,554 | $ | (61,487 | ) | $ | 1,262,846 | $ | 11 | $ | 1,201,370 | ||||||||
See accompanying Notes to Consolidated Financial Statements.
F-7
Table of Contents
Index to Financial Statements
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands)
| Years Ended December 31, | |||||||||
| 2005 | 2004 | 2003 | |||||||
| (as restated) | (as restated) | ||||||||
Net income | $ | 162,551 | $ | 138,548 | $ | 121,780 | |||
Net income on cash flow hedges | 11 | — | 16,164 | ||||||
Comprehensive income | $ | 162,562 | $ | 138,548 | $ | 137,944 | |||
See accompanying Notes to Consolidated Financial Statements.
F-8
Table of Contents
Index to Financial Statements
Notes To Consolidated Financial Statements
NOTE 1. PARTNERSHIP ORGANIZATION
TEPPCO Partners, L.P. (the “Partnership”), a Delaware limited partnership, is a master limited partnership formed in March 1990. We operate through TE Products Pipeline Company, Limited Partnership (“TE Products”), TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”). Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the “Operating Partnerships.” Texas Eastern Products Pipeline Company, LLC (the “Company” or “General Partner”), a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us.
On July 26, 2001, the Company restructured its general partner ownership of the Operating Partnerships to cause them to be indirectly wholly owned by us. TEPPCO GP, Inc. (“TEPPCO GP”), our subsidiary, succeeded the Company as general partner of the Operating Partnerships. All remaining partner interests in the Operating Partnerships not already owned by us were transferred to us. In exchange for this contribution, the Company’s interest as our general partner was increased to 2%. The increased percentage is the economic equivalent of the aggregate interest that the Company had prior to the restructuring through its combined interests in us and the Operating Partnerships. As a result, we hold a 99.999% limited partner interest in the Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest. This reorganization was undertaken to simplify required financial reporting by the Operating Partnerships when the Operating Partnerships issue guarantees of our debt.
Through February 23, 2005, the General Partner was an indirect wholly owned subsidiary of Duke Energy Field Services, LLC (“DEFS”), a joint venture between Duke Energy Corporation (“Duke Energy”) and ConocoPhillips. Duke Energy held an interest of approximately 70% in DEFS, and ConocoPhillips held the remaining interest of approximately 30%. On February 24, 2005, the General Partner was acquired by DFI GP Holdings L.P. (formerly Enterprise GP Holdings L.P.) (“DFI”), an affiliate of EPCO, Inc. (“EPCO”), a privately held company controlled by Dan L. Duncan, for approximately $1.1 billion. As a result of the transaction, DFI owns and controls the 2% general partner interest in us and has the right to receive the incentive distribution rights associated with the general partner interest. In conjunction with an amended and restated administrative services agreement, EPCO performs all management, administrative and operating functions required for us, and we reimburse EPCO for all direct and indirect expenses that have been incurred in managing us. As a result of the sale of our General Partner, DEFS and Duke Energy continued to provide some administrative services for us for a period of up to one year after the sale, at which time, we assumed these services. In connection with us assuming the operations of certain of the TEPPCO Midstream assets from DEFS, certain DEFS employees became employees of EPCO effective June 1, 2005.
At formation in 1990, we completed an initial public offering of 26,500,000 units representing Limited Partner Interests (“Limited Partner Units”) at $10.00 per Limited Partner Unit. In connection with our formation, the Company received 2,500,000 Deferred Participation Interests (“DPIs”). Effective April 1, 1994, the DPIs were converted to Limited Partner Units, but they have not been listed for trading on the New York Stock Exchange. These Limited Partner Units were assigned to Duke Energy when ownership of the Company was transferred from Duke Energy to DEFS in 2000. On February 24, 2005, DFI entered into an LP Unit Purchase and Sale Agreement with Duke Energy and purchased these 2,500,000 Limited Partner Units for $104.0 million. As of December 31, 2005, none of these Limited Partner Units had been sold by DFI.
At December 31, 2005, 2004 and 2003, we had outstanding 69,963,554, 62,998,554 and 62,998,554 Limited Partner Units, respectively. At December 31, 2002, we had outstanding 3,916,547 Class B Limited Partner Units (“Class B Units”), which were issued to Duke Energy Transport and Trading Company, LLC (“DETTCO”) in connection with an acquisition of assets initially acquired in 1998. On April 2, 2003, we repurchased and retired all of the 3,916,547 previously outstanding Class B Units with proceeds from the issuance of additional Limited Partner Units (see Note 11). Collectively, the Limited Partner Units and Class B Units are referred to as “Units”.
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
As used in this Report, “we,” “us,” “our,” the “Partnership” and “TEPPCO” mean TEPPCO Partners, L.P. and, where the context requires, include our subsidiaries.
We restated our consolidated financial statements and related financial information for the years ended December 31, 2004 and 2003, for an accounting correction. In addition, the restatement adjustment impacted quarterly periods with the fiscal years ended December 31, 2005, 2004 and 2003. See Note 20 for a discussion of the restatement adjustment and the impact on previously issued financial statements.
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
We adhere to the following significant accounting policies in the preparation of our consolidated financial statements.
Basis of Presentation and Principles of Consolidation
Throughout the consolidated financial statements and accompanying notes, all referenced amounts related to prior periods reflect the balances and amounts on a restated basis. The financial statements include our accounts on a consolidated basis. We have eliminated all significant intercompany items in consolidation. We have reclassified certain amounts from prior periods to conform to the current presentation. Our results for the years ended December 31, 2005 and 2004 reflect the operations and activities of Jonah Gas Gathering Company’s Pioneer plant as discontinued operations.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Although we believe these estimates are reasonable, actual results could differ from those estimates.
Business Segments
We operate and report in three business segments: transportation and storage of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals (“Downstream Segment”); gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals (“Upstream Segment”); and gathering of natural gas, fractionation of natural gas liquids (“NGLs”) and transportation of NGLs (“Midstream Segment”). Our reportable segments offer different products and services and are managed separately because each requires different business strategies.
Our interstate transportation operations, including rates charged to customers, are subject to regulations prescribed by the Federal Energy Regulatory Commission (“FERC”). We refer to refined products, LPGs, petrochemicals, crude oil, NGLs and natural gas in this Report, collectively, as “petroleum products” or “products.”
Revenue Recognition
Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. Transportation revenues are recognized as products are delivered to customers. Storage revenues are recognized
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
upon receipt of products into storage and upon performance of storage services. Terminaling revenues are recognized as products are out-loaded. Revenues from the sale of product inventory are recognized when the products are sold.
Our Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil, and distribution of lubrication oils and specialty chemicals principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Revenues are also generated from trade documentation and pumpover services, primarily at Cushing, Oklahoma, and Midland, Texas. Revenues are accrued at the time title to the product sold transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to our crude oil marketing company, TEPPCO Crude Oil, L.P. (“TCO”), which typically occurs upon our receipt of the product. Revenues related to trade documentation and pumpover fees are recognized as services are completed.
Except for crude oil purchased from time to time as inventory, our policy is to purchase only crude oil for which we have a market to sell and to structure sales contracts so that crude oil price fluctuations do not materially affect the margin received. As we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users or by entering into a future delivery obligation. Through these transactions, we seek to maintain a position that is balanced between crude oil purchases and sales and future delivery obligations. However, certain basis risks (the risk that price relationships between delivery points, classes of products or delivery periods will change) cannot be completely hedged.
Our Midstream Segment revenues are earned from the gathering of natural gas, transportation of NGLs and fractionation of NGLs. Gathering revenues are recognized as natural gas is received from the customer. Transportation revenues are recognized as NGLs are delivered to customers. Revenues are also earned from the sale of condensate liquid extracted from the natural gas stream to an Upstream Segment marketing affiliate. Fractionation revenues are recognized ratably over the contract year as products are delivered. We generally do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, with the exception of inventory imbalances discussed in “Natural Gas Imbalances.” Therefore, the results of our Midstream Segment are not directly affected by changes in the prices of natural gas or NGLs.
Cash and Cash Equivalents
Cash equivalents are defined as all highly marketable securities with maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximate fair value because of the short term nature of these investments.
Allowance for Doubtful Accounts
We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. The following table presents the activity of our allowance for doubtful accounts for the years ended December 31, 2005, 2004 and 2003 (in thousands):
| Years Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
Balance at beginning of period | $ | 112 | $ | 4,700 | $ | 4,608 | ||||||
Charges to expense | 829 | 536 | 793 | |||||||||
Deductions and other | (691 | ) | (5,124 | ) | (701 | ) | ||||||
Balance at end of period | $ | 250 | $ | 112 | $ | 4,700 | ||||||
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
Inventories
Inventories consist primarily of petroleum products and crude oil, which are valued at the lower of cost (weighted average cost method) or market. Our Downstream Segment acquires and disposes of various products under exchange agreements. Receivables and payables arising from these transactions are usually satisfied with products rather than cash. The net balances of exchange receivables and payables are valued at weighted average cost and included in inventories. Inventories of materials and supplies, used for ongoing replacements and expansions, are carried at the lower of fair value or cost.
Property, Plant and Equipment
We record property, plant and equipment at its acquisition cost. Additions to property, plant and equipment, including major replacements or betterments, are recorded at cost. We charge replacements and renewals of minor items of property that do not materially increase values or extend useful lives to maintenance expense. Depreciation expense is computed on the straight-line method using rates based upon expected useful lives of various classes of assets (ranging from 2% to 20% per annum).
We evaluate impairment of long-lived assets in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of the carrying amount of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or estimated fair value less costs to sell.
Asset Retirement Obligations
In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143,Accounting for Asset Retirement Obligations. SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which we incur a legal obligation for the retirement of tangible long-lived assets. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement of the asset retirement obligation, the liability will be adjusted at the end of each reporting period to reflect changes in the estimated future cash flows underlying the obligation. Determination of any amounts recognized upon adoption is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates.
The Downstream Segment assets consist primarily of an interstate trunk pipeline system and a series of storage facilities that originate along the upper Texas Gulf Coast and extend through the Midwest and northeastern United States. We transport refined products, LPGs and petrochemicals through the pipeline system. These products are primarily received in the south end of the system and stored and/or transported to various points along the system per customer nominations. The Upstream Segment’s operations include purchasing crude oil from producers at the wellhead and providing delivery, storage and other services to its customers. The properties in the Upstream Segment consist of interstate trunk pipelines, pump stations, trucking facilities, storage tanks and various gathering systems primarily in Texas and Oklahoma. The Midstream Segment gathers natural gas from wells owned by producers and delivers natural gas and NGLs on its pipeline systems, primarily in Texas, Wyoming, New Mexico and Colorado. The Midstream Segment also owns and operates two NGL fractionator facilities in Colorado.
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
We have completed our assessment of SFAS 143, and we have determined that we are obligated by contractual or regulatory requirements to remove certain facilities or perform other remediation upon retirement of our assets. However, we are not able to reasonably determine the fair value of the asset retirement obligations for our trunk, interstate and gathering pipelines and our surface facilities, since future dismantlement and removal dates are indeterminate.
In order to determine a removal date for our gathering lines and related surface assets, reserve information regarding the production life of the specific field is required. As a transporter and gatherer of crude oil and natural gas, we are not a producer of the field reserves, and we therefore do not have access to adequate forecasts that predict the timing of expected production for existing reserves on those fields in which we gather crude oil and natural gas. In the absence of such information, we are not able to make a reasonable estimate of when future dismantlement and removal dates of our gathering assets will occur. With regard to our trunk and interstate pipelines and their related surface assets, it is impossible to predict when demand for transportation of the related products will cease. Our right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, we can evaluate our trunk pipelines for alternative uses, which can be and have been found.
We will record such asset retirement obligations in the period in which more information becomes available for us to reasonably estimate the settlement dates of the retirement obligations. The adoption of SFAS 143 did not have an effect on our financial position, results of operations or cash flows.
Capitalization of Interest
We capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 5.73%, 5.74% and 6.50% for the years ended December 31, 2005, 2004 and 2003, respectively. During the years ended December 31, 2005, 2004 and 2003, the amount of interest capitalized was $6.8 million, $4.2 million and $5.3 million, respectively.
Intangible Assets
Intangible assets on the consolidated balance sheets consist primarily of gathering contracts assumed in the acquisition of Jonah Gas Gathering System (“Jonah”) on September 30, 2001, and the acquisition of Val Verde Gathering System (“Val Verde”) on June 30, 2002, a fractionation agreement and other intangible assets (see Note 3). Included in equity investments on the consolidated balance sheets are excess investments in Centennial Pipeline LLC (“Centennial”) and Seaway Crude Pipeline Company (“Seaway”).
In connection with the acquisitions of Jonah and Val Verde, we assumed contracts that dedicate future production from natural gas wells in the Green River Basin in Wyoming, and we assumed fixed-term contracts with customers that gather coal bed methane (“CBM”) from the San Juan Basin in New Mexico and Colorado, respectively. The value assigned to these intangible assets relates to contracts with customers that are for either a fixed term or which dedicate total future lease production to the gathering system. These intangible assets are amortized on a unit-of-production basis, based upon the actual throughput of the system over the expected total throughput for the lives of the contracts. Revisions to the unit-of-production estimates may occur as additional production information is made available to us (see Note 3).
In connection with the purchase of the fractionation facilities in 1998, we entered into a fractionation agreement with DEFS. The fractionation agreement is being amortized on a straight-line basis over a period of 20 years, which is the term of the agreement with DEFS.
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
In connection with the acquisition of crude supply and transportation assets in November 2003, we acquired intangible customer contracts for $8.7 million, which are amortized on a unit-of-production basis (see Note 5).
In connection with the formation of Centennial, we recorded excess investment, the majority of which is amortized on a unit-of-production basis over a period of 10 years. In connection with the acquisition of our interest in Seaway, we recorded excess investment, which is amortized on a straight-line basis over a period of 39 years (see Note 3).
Goodwill
Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization. We account for goodwill under SFAS No. 142,Goodwill and Other Intangible Assets, which was issued by the FASB in July 2001 (see Note 3). SFAS 142 prohibits amortization of goodwill and intangible assets with indefinite useful lives, but instead requires testing for impairment at least annually. SFAS 142 requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives. Beginning January 1, 2002, effective with the adoption of SFAS 142, we no longer record amortization expense related to goodwill.
Environmental Expenditures
We accrue for environmental costs that relate to existing conditions caused by past operations. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as damages and other costs, when estimable. We monitor the balance of accrued undiscounted environmental liabilities on a regular basis. We record liabilities for environmental costs at a specific site when our liability for such costs is probable and a reasonable estimate of the associated costs can be made. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation alternatives available and the evolving nature of environmental laws and regulations.
The following table presents the activity of our environmental reserve for the years ended December 31, 2005, 2004 and 2003 (in thousands):
| Years Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
Balance at beginning of period | $ | 5,037 | $ | 7,639 | $ | 7,693 | ||||||
Charges to expense | 2,530 | 5,178 | 6,824 | |||||||||
Deductions and other | (5,120 | ) | (7,780 | ) | (6,878 | ) | ||||||
Balance at end of period | $ | 2,447 | $ | 5,037 | $ | 7,639 | ||||||
Natural Gas Imbalances
Gas imbalances occur when gas producers (customers) deliver more or less actual natural gas gathering volumes to our gathering systems than they originally nominated. Actual deliveries are different from nominated volumes due to fluctuations in gas production at the wellhead. If the customers supply more natural gas gathering
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
volumes than they nominated, Val Verde and Jonah record a payable for the amount due to customers and also record a receivable for the same amount due from connecting pipeline transporters or shippers. To the extent that these amounts are not cashed out monthly on Val Verde, if the customers supply less natural gas gathering volumes than they nominated, Val Verde and Jonah record a receivable reflecting the amount due from customers and a payable for the same amount due to connecting pipeline transporters or shippers. We record natural gas imbalances using a mark-to-market approach.
Income Taxes
We are a limited partnership. As such, we are not a taxable entity for federal and state income tax purposes and do not directly pay federal and state income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statements of income, is includable in the federal and state income tax returns of each unitholder. Accordingly, no recognition has been given to federal and state income taxes for our operations. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each unitholders’ tax attributes in the Partnership.
Use of Derivatives
We account for derivative financial instruments in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities,and SFAS No. 138,Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133.These statements establish accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet at fair value as either assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative.
Our derivative instruments consist primarily of interest rate swaps and contracts for the purchase and sale of petroleum products in connection with our crude oil marketing activities. Substantially all derivative instruments related to our crude oil marketing activities meet the normal purchases and sales criteria of SFAS 133, as amended, and as such, changes in the fair value of petroleum product purchase and sales agreements are reported on the accrual basis of accounting. SFAS 133 describes normal purchases and sales as contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business.
For all hedging relationships, we formally document at inception the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed and a description of the method of measuring ineffectiveness. This process includes linking all derivatives that are designated as fair value or cash flow to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. We also formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively.
For derivative instruments designated as fair value hedges, gains and losses on the derivative instrument are offset against related results on the hedged item in the statement of income. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a fair value hedge, along with the loss or
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
gain on the hedged asset or liability or unrecognized firm commitment of the hedged item that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective as a hedge, until earnings are affected by the variability in cash flows of the designated hedged item. Hedge effectiveness is measured at least quarterly based on the relative cumulative changes in fair value between the derivative contract and the hedged item over time. The ineffective portion of the change in fair value of a derivative instrument that qualifies as either a fair value hedge or a cash flow hedge is reported immediately in earnings.
According to SFAS 133, as amended, we are required to discontinue hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the fair value or cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is de-designated as a hedging instrument, because it is unlikely that a forecasted transaction will occur, a hedged firm commitment no longer meets the definition of a firm commitment, or management determines that designation of the derivative as a hedging instrument is no longer appropriate.
When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective fair value hedge, we continue to carry the derivative on the balance sheet at its fair value and no longer adjust the hedged asset or liability for changes in fair value. The adjustment of the carrying amount of the hedged asset or liability is accounted for in the same manner as other components of the carrying amount of that asset or liability. When hedge accounting is discontinued because the hedged item no longer meets the definition of a firm commitment, we continue to carry the derivative on the balance sheet at its fair value, remove any asset or liability that was recorded pursuant to recognition of the firm commitment from the balance sheet, and recognize any gain or loss in earnings. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, we continue to carry the derivative on the balance sheet at its fair value with subsequent changes in fair value included in earnings, and gains and losses that were accumulated in other comprehensive income are recognized immediately in earnings. In all other situations in which hedge accounting is discontinued, we continue to carry the derivative at its fair value on the balance sheet and recognize any subsequent changes in its fair value in earnings.
Fair Value of Financial Instruments
The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable and accrued liabilities, other current liabilities and derivatives approximates their fair value due to their short-term nature. The fair values of these financial instruments are represented in our consolidated balance sheets.
Net Income Per Unit
Basic net income per Unit is computed by dividing net income, after deduction of the General Partner’s interest, by the weighted average number of Units outstanding (a total of 67.4 million Units, 63.0 million Units and 59.8 million Units for the years ended December 31, 2005, 2004 and 2003, respectively). The General Partner’s percentage interest in our net income is based on its percentage of cash distributions from Available Cash for each year (see Note 11). The General Partner was allocated $47.6 million (representing 29.27%) of net income for the year ended December 31, 2005, $40.0 million (representing 28.85%) of net income for the year ended December 31, 2004, and $33.7 million (representing 27.65%) of net income for the year ended December 31, 2003. The General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase, in accordance with our limited partnership agreement.
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
Diluted net income per Unit is similar to the computation of basic net income per Unit discussed above, except that the denominator is increased to include the dilutive effect of outstanding Unit options by application of the treasury stock method. For the year ended December 31, 2003, the denominator was increased by 11,878 Units. For the years ended December 31, 2005 and 2004, diluted net income per Unit equaled basic net income per Unit as all remaining outstanding Unit options were exercised during the third quarter of 2003 (see Note 13).
Unit Option Plan
We have not granted options for any periods presented. For options outstanding under the 1994 Long Term Incentive Plan (see Note 13), we followed the intrinsic value method of accounting for recognizing stock-based compensation expense. Under this method, we record no compensation expense for Unit options granted when the exercise price of the options granted is equal to, or greater than, the market price of our Units on the date of the grant. During the year ended December 31, 2003, all remaining outstanding Unit options were exercised.
In December 2002, SFAS No. 148,Accounting for Stock-Based Compensation—Transition and Disclosure was issued. SFAS 148 amends SFAS No. 123,Accounting for Stock-Based Compensation, and provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002, and are included in Note 13.
Assuming we had used the fair value method of accounting for our Unit option plan, pro forma net income would equal reported net income for the years ended December 31, 2005, 2004 and 2003. Pro forma net income per Unit would equal reported net income per Unit for the periods presented. The adoption of SFAS 148 did not have an effect on our financial position, results of operations or cash flows.
New Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123(R),Share-Based Payment. SFAS 123(R) requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of the compensation cost is to be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards are to be re-measured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) is a revision of SFAS No. 123,Accounting for Stock-Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure and supersedes Accounting Principles Board (“APB”) Opinion No. 25,Accounting for Stock Issued to Employees. SFAS 123(R) is effective for public companies as of the first interim or annual reporting period of the first fiscal year beginning after June 15, 2005. The Securities and Exchange Commission amended the implementation date of SFAS 123(R) to begin with the first interim or annual reporting period of the company’s first fiscal year beginning on or after June 15, 1005. As such, we will adopt SFAS 123(R) in the first quarter of 2006. Companies are permitted to adopt SFAS 123(R) prior to the extended date. All public companies that adopted the fair-value-based method of accounting must use the modified prospective transition method and may elect to use the modified retrospective transition method. We do not believe that the adoption of SFAS 123(R) will have a material effect on our financial position, results of operations or cash flows.
In November 2004, the Emerging Issues Task Force (“EITF”) reached consensus in EITF 03-13,Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for Impairment or Disposal of Long-
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
Lived Assets, in Determining Whether to Report Discontinued Operations, to clarify whether a component of an enterprise that is either disposed of or classified as held for sale qualifies for income statement presentation as discontinued operations. The FASB ratified the consensus on November 30, 2004. The consensus is to be applied prospectively with regard to a component of an enterprise that is either disposed of or classified as held for sale in reporting periods beginning after December 15, 2004. The consensus may be applied retrospectively for previously reported operating results related to disposal transactions initiated within an enterprise’s reporting period that included the date that this consensus was ratified. The adoption of EITF 03-13 did not have an effect on our financial position, results of operations or cash flows.
In March 2005, the FASB issued FASB Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (“FIN 47”). FIN 47 clarifies that the term, conditional asset retirement obligation as used in SFAS No. 143,Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the control of the entity. Even though uncertainty about the timing and/or method of settlement exists and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred generally upon acquisition, construction, or development or through the normal operation of the asset. SFAS 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of reporting periods ending after December 15, 2005, and early adoption of FIN 47 is encouraged. We adopted FIN 47 in the fourth quarter of 2005. The adoption of FIN 47 did not have a material effect on our financial position, results of operations or cash flows.
In June 2005, the EITF reached consensus in EITF 04-5,Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights, to provide guidance on how general partners in a limited partnership should determine whether they control a limited partnership and therefore should consolidate it. The EITF agreed that the presumption of general partner control would be overcome only when the limited partners have either of two types of rights. The first type, referred to as kick-out rights, is the right to dissolve or liquidate the partnership or otherwise remove the general partner without cause. The second type, referred to as participating rights, is the right to effectively participate in significant decisions made in the ordinary course of the partnership’s business. The kick-out rights and the participating rights must be substantive in order to overcome the presumption of general partner control. The consensus is effective for general partners of all new limited partnerships formed and for existing limited partnerships for which the partnership agreements are modified subsequent to the date of FASB ratification (June 29, 2005). For existing limited partnerships that have not been modified, the guidance in EITF 04-5 is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005. We do not believe that the adoption of EITF 04-5 will have a material effect on our financial position, results of operations or cash flows.
In December 2004, the FASB issued SFAS No. 153,Exchanges of Nonmonetary Assets, an amendment of APB Opinion 29. SFAS 153 amends APB Opinion No. 29,Accounting for Nonmonetary Exchanges,to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the
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exchange. SFAS 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. We adopted SFAS 153 during the second quarter of 2005. The adoption of SFAS 153 did not have a material effect on our financial position, results of operations or cash flows.
In May 2005, the FASB issued SFAS No. 154,Accounting Changes and Error Corrections. SFAS 154 establishes new standards on accounting for changes in accounting principles. All such changes must be accounted for by retrospective application to the financial statements of prior periods unless it is impracticable to do so. SFAS 154 completely replaces APB Opinion No. 20,Accounting Changes,and SFAS No. 3,Reporting Accounting Changes in Interim Periods. However, it carries forward the guidance in those pronouncements with respect to accounting for changes in estimates, changes in the reporting entity, and the correction of errors. SFAS 154 is effective for accounting changes and error corrections made in fiscal years beginning after December 15, 2005, with early adoption permitted for changes and corrections made in years beginning after June 1, 2005. The application of SFAS 154 does not affect the transition provisions of any existing pronouncements, including those that are in the transition phase as of the effective date of SFAS 154. We do not believe that the adoption of SFAS 154 will have a material effect on our financial position, results of operations or cash flows.
In September 2005, the EITF reached consensus in EITF 04-13,Accounting for Purchases and Sales of Inventory with the Same Counterparty, to define when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction subject to APB Opinion No. 29,Accounting for Nonmonetary Transactions. Two or more inventory transactions with the same party should be combined if they are entered into in contemplation of one another. The EITF also requires entities to account for exchanges of inventory in the same line of business at fair value or recorded amounts based on inventory classification. The guidance in EITF 04-13 is effective for new inventory arrangements entered into in reporting periods beginning after March 15, 2006. We are currently evaluating what impact EITF 04-13 will have on our financial statements, but at this time we do not believe that the adoption of EITF 04-13 will have a material effect on our financial position, results of operations or cash flows.
NOTE 3. Goodwill And Other Intangible Assets
Goodwill
Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization. We account for goodwill under SFAS No. 142,Goodwill and Other Intangible Assets,which was issued by the FASB in July 2001. SFAS 142 prohibits amortization of goodwill and intangible assets with indefinite useful lives, but instead requires testing for impairment at least annually. We test goodwill and intangible assets for impairment annually at December 31.
To perform an impairment test of goodwill, we have identified our reporting units and have determined the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units. We then determine the fair value of each reporting unit and compare it to the carrying value of the reporting unit. We will continue to compare the fair value of each reporting unit to its carrying value on an annual basis to determine if an impairment loss has occurred. There have been no goodwill impairment losses recorded since the adoption of SFAS 142.
The following table presents the carrying amount of goodwill at December 31, 2005 and 2004, by business segment (in thousands):
| Downstream Segment | Midstream Segment | Upstream Segment | Segments Total | |||||||||
Goodwill | $ | — | $ | 2,777 | $ | 14,167 | $ | 16,944 | ||||
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Notes to Consolidated Financial Statements — Continued
Other Intangible Assets
The following table reflects the components of intangible assets, including excess investments, being amortized at December 31, 2005 and 2004 (in thousands):
| December 31, 2005 | December 31, 2004 | |||||||||||||
Gross Amount | Accumulated Amortization | Gross Amount | Accumulated Amortization | |||||||||||
Intangible assets: | ||||||||||||||
Gathering and transportation agreements | $ | 464,337 | $ | (118,921 | ) | $ | 464,337 | $ | (91,262 | ) | ||||
Fractionation agreement | 38,000 | (14,725 | ) | 38,000 | (12,825 | ) | ||||||||
Other | 10,226 | (2,009 | ) | 12,262 | (3,154 | ) | ||||||||
Subtotal | $ | 512,563 | $ | (135,655 | ) | $ | 514,599 | $ | (107,241 | ) | ||||
Excess investments: | ||||||||||||||
Centennial Pipeline LLC | $ | 33,400 | $ | (12,947 | ) | $ | 33,400 | $ | (8,875 | ) | ||||
Seaway Crude Pipeline Company | 27,100 | (3,764 | ) | 27,100 | (3,072 | ) | ||||||||
Subtotal | $ | 60,500 | $ | (16,711 | ) | $ | 60,500 | $ | (11,947 | ) | ||||
Total intangible assets | $ | 573,063 | $ | (152,366 | ) | $ | 575,099 | $ | (119,188 | ) | ||||
SFAS 142 requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. Amortization expense on intangible assets was $30.5 million, $32.2 million and $36.2 million for the years ended December 31, 2005, 2004 and 2003, respectively. Amortization expense on excess investments included in equity earnings was $4.8 million, $3.8 million and $4.0 million for the years ended December 31, 2005, 2004 and 2003, respectively.
The values assigned to our intangible assets for natural gas gathering contracts on the Jonah and the Val Verde systems are amortized on a unit-of-production basis, based upon the actual throughput of the systems compared to the expected total throughput for the lives of the contracts. On a quarterly basis, we may obtain limited production forecasts and updated throughput estimates from some of the producers on the systems, and as a result, we evaluate the remaining expected useful lives of the contract assets based on the best available information. During the fourth quarter of 2004 and the first and second quarters of 2005, certain limited production forecasts were obtained from some of the producers on the Jonah system related to future expansions of the system, and as a result, we increased our best estimate of future throughput on the system, which resulted in extensions in the remaining lives of the intangible assets. During the fourth quarter of 2004 and the third quarter of 2005, certain limited coal bed methane production forecasts were obtained from some of the producers on the Val Verde system whose contracts are included in the intangible assets. These forecasts indicated lower coal bed methane production estimates over the contract periods, and as a result, we decreased our best estimate of future throughput on the Val Verde system, which resulted in increases to amortization expense on the intangible assets. Further revisions to these estimates may occur as additional production information is made available to us.
The values assigned to our fractionation agreement and other intangible assets are generally amortized on a straight-line basis. Our fractionation agreement is being amortized over its contract period of 20 years. The amortization periods for our other intangible assets, which include non-compete and other agreements, range
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from 3 years to 15 years. The value of $8.7 million assigned to our crude supply and transportation intangible customer contracts is being amortized on a unit-of-production basis (see Note 5).
The value assigned to our excess investment in Centennial was created upon its formation. Approximately $30.0 million is related to a contract and is being amortized on a unit-of-production basis based upon the volumes transported under the contract compared to the guaranteed total throughput of the contract over a 10-year life. The remaining $3.4 million is related to a pipeline and is being amortized on a straight-line basis over the life of the pipeline, which is 35 years. The value assigned to our excess investment in Seaway was created upon acquisition of our 50% ownership interest in 2000. We are amortizing the $27.1 million excess investment in Seaway on a straight-line basis over a 39-year life related primarily to the life of the pipeline.
The following table sets forth the estimated amortization expense of intangible assets and the estimated amortization expense allocated to equity earnings for the years ending December 31 (in thousands):
| Intangible Assets | Excess Investments | |||||
2006 | $ | 32,561 | $ | 4,691 | ||
2007 | 33,395 | 5,113 | ||||
2008 | 32,967 | 5,438 | ||||
2009 | 30,719 | 6,878 | ||||
2010 | 27,338 | 7,042 | ||||
NOTE 4. INTEREST RATE SWAPS
In July 2000, we entered into an interest rate swap agreement to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility. This interest rate swap matured in April 2004. We designated this swap agreement, which hedged exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement was based on a notional amount of $250.0 million. Under the swap agreement, we paid a fixed rate of interest of 6.955% and received a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this swap was designated as a cash flow hedge, the changes in fair value, to the extent the swap was effective, were recognized in other comprehensive income until the hedged interest costs were recognized in earnings. During the years ended December 31, 2004 and 2003, we recognized an increase in interest expense of $2.9 million and $14.4 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.
In October 2001, TE Products entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as a fair value hedge. The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes. Under the swap agreement, TE Products pays a floating rate of interest based on a three-month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. During the years ended December 31, 2005, 2004 and 2003, we recognized reductions in interest expense of $5.6 million, $9.6 million and $10.0 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the years ended December 31, 2005, 2004 and 2003, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of this interest rate swap was a loss of approximately $0.9 million at December 31, 2005, and a gain of approximately $3.4 million at December 31, 2004.
During 2002, we entered into interest rate swap agreements, designated as fair value hedges, to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. The swap agreements had
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a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under the swap agreements, we paid a floating rate of interest based on a U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. These swap agreements were later terminated in 2002 resulting in gains of $44.9 million. The gains realized from the swap terminations have been deferred as adjustments to the carrying value of the Senior Notes and are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the Senior Notes. At December 31, 2005, the unamortized balance of the deferred gains was $32.4 million. In the event of early extinguishment of the Senior Notes, any remaining unamortized gains would be recognized in the consolidated statement of income at the time of extinguishment.
During May 2005, we executed a treasury rate lock agreement with a notional amount of $200.0 million to hedge our exposure to increases in the treasury rate that was to be used to establish the fixed interest rate for a debt offering that was proposed to occur in the second quarter of 2005. During June 2005, the proposed debt offering was cancelled, and the treasury lock was terminated with a realized loss of $2.0 million. The realized loss was recorded as a component of interest expense in the consolidated statements of income in June 2005.
NOTE 5. ACQUISITIONS, DISPOSITIONS AND DISCONTINUED OPERATIONS
Rancho Pipeline
In connection with our acquisition of crude oil assets in 2000, we acquired an approximate 23.5% undivided joint interest in the Rancho Pipeline, which was a crude oil pipeline system from West Texas to Houston, Texas. In March 2003, the Rancho Pipeline ceased operations, and segments of the pipeline were sold to certain of the owners that previously held undivided interests in the pipeline. We acquired 241 miles of the pipeline in exchange for cash of $5.5 million and our interests in other portions of the Rancho Pipeline. We sold 183 miles of the segment we acquired to other entities for cash and assets valued at approximately $8.5 million. We recorded a net gain of $3.9 million on the transactions in the second quarter of 2003. During the third quarter of 2004, we sold our remaining interest in the original Rancho Pipeline system for a net gain of $0.4 million. These gains are included in the gains on sales of assets in our consolidated statements of income in the 2004 period.
Genesis Pipeline
On November 1, 2003, we purchased crude supply and transportation assets along the upper Texas Gulf Coast for $21.0 million from Genesis Crude Oil, L.P. and Genesis Pipeline Texas, L.P. (“Genesis”). The transaction was funded with proceeds from our August 2003 equity offering (see Note 11). We allocated the purchase price, net of liabilities assumed, primarily to property, plant and equipment and intangible assets. The assets acquired included approximately 150 miles of small diameter trunk lines, 26,000 barrels per day of throughput and 12,000 barrels per day of lease marketing and supply business. We have integrated these assets into our South Texas pipeline system, which has allowed us to consolidate gathering and marketing assets in key operating areas in a cost effective manner and will provide future growth opportunities. Accordingly, the results of the acquisition are included in the consolidated financial statements from November 1, 2003.
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Notes to Consolidated Financial Statements — Continued
The following table allocates the estimated fair value of the Genesis assets acquired on November 1, 2003 (in thousands):
Property, plant and equipment | $ | 12,811 | ||
Intangible assets | 8,742 | |||
Other | 144 | |||
Total assets | 21,697 | |||
Total liabilities assumed | (687 | ) | ||
Net assets acquired | $ | 21,010 | ||
Mexia Pipeline
On March 31, 2005, we purchased crude oil pipeline assets for $7.1 million from BP Pipelines (North America) Inc. (“BP”). The assets include approximately 158 miles of pipeline, which extend from Mexia, Texas, to the Houston, Texas, area and two stations in south Houston with connections to a BP pipeline that originates in south Houston. We funded the purchase through borrowings under our revolving credit facility. We allocated the purchase price to property, plant and equipment, and we accounted for the acquisition of these assets under the purchase method of accounting. We have integrated these assets into our South Texas pipeline system, included in our Upstream Segment, which will allow us to realize synergies within our existing asset base and will provide future growth opportunities.
Crude Oil Storage and Terminaling Assets
On April 1, 2005, we purchased crude oil storage and terminaling assets in Cushing, Oklahoma, from Koch Supply & Trading, L.P. for $35.4 million. The assets consist of eight storage tanks with 945,000 barrels of storage capacity, receipt and delivery manifolds, interconnections to several pipelines, crude oil inventory and approximately 70 acres of land. We funded the purchase through borrowings under our revolving credit facility. We allocated the purchase price to property, plant and equipment and inventory, and we accounted for the acquisition of these assets under the purchase method of accounting. The storage and terminaling assets complement our existing infrastructure in Cushing and strengthen our gathering and marketing business in our Upstream Segment.
Refined Products Terminal and Truck Rack
On July 12, 2005, we purchased a refined products terminal and truck loading rack in North Little Rock, Arkansas, for $6.9 million from ExxonMobil Corporation. The assets include three storage tanks and a two-bay truck loading rack. We funded the purchase through borrowings under our revolving credit facility. We allocated the purchase price to property, plant and equipment and inventory, and we accounted for the acquisition of these assets under the purchase method of accounting. The terminal serves the central Arkansas refined products market and complements our existing Downstream Segment infrastructure in North Little Rock, Arkansas.
Genco Assets
On July 15, 2005, we acquired from Texas Genco, LLC (“Genco”) all of its interests in certain companies that own a 90-mile pipeline system and 5.5 million barrels of storage capacity for $62.1 million. We funded the purchase through borrowings under our revolving credit facility. We allocated the purchase price to property, plant and equipment, and we accounted for the acquisition of these assets under the purchase method of
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accounting. The assets of the purchased companies will be integrated into our Downstream Segment origin infrastructure in Texas City and Baytown, Texas. As a result of this acquisition, we initiated the expansion of refined products origin capabilities in the Houston and Texas City, Texas, areas. The integration and other system enhancements should be in service by the fourth quarter of 2006, at an estimated cost of $45.0 million. The strategic location of these assets, with refined products interconnections to major exchange terminals in the Houston area, will provide significant long-term value to our customers and our Texas Gulf Coast refining and logistics system.
Pioneer Plant
On January 26, 2006, we announced the execution of a letter of intent to sell our ownership interest in the Pioneer silica gel natural gas processing plant located near Opal, Wyoming, together with Jonah’s rights to process natural gas originating from the Jonah and Pinedale fields, located in southwest Wyoming, to an affiliate of Enterprise Products Partners L.P. (“Enterprise”). On March 31, 2006, we sold the Pioneer plant to an affiliate of Enterprise for $38.0 million in cash. The Pioneer plant, included in our Midstream Segment, was not an integral part of our operations and natural gas processing is not a core business. The Pioneer plant was constructed as part of the Phase III expansion of the Jonah system and was completed during the first quarter of 2004. We have no continuing involvement in the operations or results of this plant. This transaction was reviewed and approved by the Audit and Conflicts Committee of the board of directors of our General Partner and of the general partner of Enterprise, and a fairness opinion was rendered by an independent third-party.
Condensed statements of income for the Pioneer plant, which is classified as discontinued operations, for the years ended December 31, 2005 and 2004, are presented below (in thousands):
| Years Ended December 31, | ||||||
| 2005 | 2004 | |||||
Sales of petroleum products | $ | 10,479 | $ | 7,295 | ||
Other | 2,975 | 2,807 | ||||
Total operating revenues | 13,454 | 10,102 | ||||
Purchases of petroleum products | 8,870 | 5,944 | ||||
Operating, general and administrative | 692 | 738 | ||||
Depreciation and amortization | 612 | 610 | ||||
Taxes—other than income taxes | 130 | 121 | ||||
Total costs and expenses | 10,304 | 7,413 | ||||
Income from discontinued operations | $ | 3,150 | $ | 2,689 | ||
Assets of the discontinued operations consisted of the following at December 31, 2005 and 2004 (in thousands):
| December 31, | ||||||
| 2005 | 2004 | |||||
Inventories | $ | 7 | $ | 28 | ||
Property, plant and equipment, net | 19,812 | 20,598 | ||||
Assets of discontinued operations | $ | 19,819 | $ | 20,626 | ||
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Notes to Consolidated Financial Statements — Continued
Net cash flows from discontinued operations for the years ended December 31, 2005 and 2004, are presented below (in thousands):
| Years Ended December 31, | |||||||||||
| 2005 | 2004 | 2003 | |||||||||
Cash flows from discontinued operating activities: | |||||||||||
Net income | $ | 3,150 | $ | 2,689 | $ | — | |||||
Depreciation and amortization | 612 | 610 | — | ||||||||
(Increase) decrease in inventories | 20 | (28 | ) | — | |||||||
Net cash flows provided by discontinued operating activities | 3,782 | 3,271 | — | ||||||||
Cash flows from discontinued investing activities: | |||||||||||
Capital expenditures | — | (7,398 | ) | (13,810 | ) | ||||||
Net cash flows used in discontinued investing activities | — | (7,398 | ) | (13,810 | ) | ||||||
Net cash flows from discontinued operations | $ | 3,782 | $ | (4,127 | ) | $ | (13,810 | ) | |||
NOTE 6. EQUITY INVESTMENTS
Through one of our indirect wholly owned subsidiaries, we own a 50% ownership interest in Seaway. The remaining 50% interest is owned by ConocoPhillips. We operate the Seaway assets. Seaway owns a pipeline that carries mostly imported crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal at Texas City, Texas, to refineries in the Texas City and Houston, Texas, areas. The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of Seaway. From June 2002 through May 2006, we receive 60% of revenue and expense of Seaway. Thereafter, we will receive 40% of revenue and expense of Seaway. During the years ended December 31, 2005, 2004 and 2003, we received distributions from Seaway of $24.7 million, $36.9 million and $22.7 million, respectively.
In August 2000, TE Products entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”), a former subsidiary of CMS Energy Corporation, and Marathon Petroleum Company LLC (“Marathon”) to form Centennial. Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois. Through February 9, 2003, each participant owned a one-third interest in Centennial. On February 10, 2003, TE Products and Marathon each acquired an additional 16.7% interest in Centennial from PEPL for $20.0 million each, increasing their ownership percentages in Centennial to 50% each. During the year ended December 31, 2005, TE Products did not make any additional investments in Centennial. TE Products invested an additional $1.5 million and $24.0 million, respectively, in Centennial, in 2004 and 2003, which is included in the equity investment balance at December 31, 2005. The 2003 amount includes the $20.0 million paid for the acquisition of the additional ownership interest in Centennial. TE Products has not received any distributions from Centennial since its formation.
On January 1, 2003, TE Products and Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”) formed Mont Belvieu Storage Partners, L.P. (“MB Storage”). TE Products and Louis Dreyfus each own a 50% ownership interest in MB Storage. MB Storage owns storage capacity at the Mont Belvieu fractionation and storage complex and a short haul transportation shuttle system that ties Mont Belvieu, Texas, to the upper Texas Gulf Coast energy marketplace. MB Storage is a service-oriented, fee-based venture serving the fractionation, refining and petrochemical industries with substantial capacity and flexibility for the transportation, terminaling and storage of NGLs, LPGs and refined products. MB Storage has no commodity trading activity. TE Products operates the facilities for MB Storage. Effective January 1, 2003, TE Products contributed property and
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Notes to Consolidated Financial Statements — Continued
equipment with a net book value of $67.1 million to MB Storage. Additionally, as of the contribution date, Louis Dreyfus had invested $6.1 million for expansion projects for MB Storage that TE Products was required to reimburse if the original joint development and marketing agreement was terminated by either party. This deferred liability was also contributed and credited to the capital account of Louis Dreyfus in MB Storage.
For the year ended December 31, 2005, TE Products received the first $1.7 million per quarter (or $6.78 million on an annual basis) of MB Storage’s income before depreciation expense, as defined in the operating agreement. For the year ended December 31, 2004, TE Products received the first $1.8 million per quarter (or $7.15 million on an annual basis) of MB Storage’s income before depreciation expense. TE Products’ share of MB Storage’s earnings is adjusted annually by the partners of MB Storage. Any amount of MB Storage’s annual income before depreciation expense in excess of $6.78 million for 2005 and $7.15 million for 2004 was allocated evenly between TE Products and Louis Dreyfus. Depreciation expense on assets each party originally contributed to MB Storage is allocated between TE Products and Louis Dreyfus based on the net book value of the assets contributed. Depreciation expense on assets constructed or acquired by MB Storage subsequent to formation is allocated evenly between TE Products and Louis Dreyfus. For the years ended December 31, 2005, 2004 and 2003, TE Products’ sharing ratio in the earnings of MB Storage was 64.2%, 69.4% and 70.4%, respectively. During the years ended December 31, 2005, 2004 and 2003, TE Products received distributions of $12.4 million, $10.3 million and $5.3 million, respectively, from MB Storage. During the years ended December 31, 2005, 2004 and 2003, TE Products contributed $5.6 million, $21.4 million and $2.5 million, respectively, to MB Storage. The 2005 contribution includes a combination of non-cash asset transfers of $1.4 million and cash contributions of $4.2 million. The 2004 contribution includes $16.5 million for the acquisition of storage and pipeline assets in April 2004. The remaining contributions have been for capital expenditures.
We use the equity method of accounting to account for our investments in Seaway, Centennial and MB Storage. Summarized combined financial information for Seaway, Centennial and MB Storage for the years ended December 31, 2005 and 2004, is presented below (in thousands):
| Years Ended December 31, | ||||||
| 2005 | 2004 | |||||
Revenues | $ | 164,494 | $ | 149,843 | ||
Net income | 52,623 | 52,059 | ||||
Summarized combined balance sheet information for Seaway, Centennial and MB Storage as of December 31, 2005 and 2004, is presented below (in thousands):
| December 31, | ||||||
| 2005 | 2004 | |||||
Current assets | $ | 60,082 | $ | 59,314 | ||
Noncurrent assets | 630,212 | 633,222 | ||||
Current liabilities | 42,242 | 41,209 | ||||
Long-term debt | 140,000 | 140,000 | ||||
Noncurrent liabilities | 13,626 | 20,440 | ||||
Partners’ capital | 494,426 | 490,887 | ||||
NOTE 7. RELATED PARTY TRANSACTIONS
EPCO and Affiliates and Duke Energy, DEFS and Affiliates
The Partnership does not have any employees. We are managed by the Company, which, for all periods prior to February 23, 2005, was an indirect wholly owned subsidiary of DEFS. According to the Partnership
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Notes to Consolidated Financial Statements — Continued
Agreement, the Company was entitled to reimbursement of all direct and indirect expenses related to our business activities. As a result of the change in ownership of the General Partner on February 24, 2005, all of our management, administrative and operating functions are performed by employees of EPCO, pursuant to an administrative services agreement. We reimburse EPCO for the costs of its employees who perform operating functions for us and for costs related to its other management and administrative employees (see Note 1).
The following table summarizes the related party transactions with EPCO and affiliates and DEFS and affiliates for the periods indicated (in millions):
| Years Ended December 31, | |||||||||
| 2005 | 2004 | 2003 | |||||||
Revenues from EPCO and affiliates(1) | |||||||||
Transportation—NGLs(2) | $ | 7.4 | $ | — | $ | — | |||
Transportation—LPGs(3) | 4.3 | — | — | ||||||
Other operating revenues(4) | 0.3 | — | — | ||||||
Costs and Expenses from EPCO and affiliates(1) | |||||||||
Payroll and administrative(5) | 68.2 | — | — | ||||||
Purchases of petroleum products(6) | 3.4 | — | — | ||||||
Revenues from DEFS and affiliates(7) | |||||||||
Sales of petroleum products(8) | 4.3 | 23.2 | 15.2 | ||||||
Transportation—NGLs(9) | 2.8 | 16.7 | 17.2 | ||||||
Gathering—Natural gas—Jonah(10) | 0.5 | 3.3 | 2.0 | ||||||
Transportation—LPGs(11) | 0.7 | 2.6 | 2.8 | ||||||
Other operating revenues(12) | 2.4 | 14.0 | 10.8 | ||||||
Costs and Expenses from DEFS and affiliates(7)(13)(14) | |||||||||
Payroll and administrative(5) | 16.2 | 95.9 | 88.8 | ||||||
Purchases of petroleum products—TCO(15) | 37.7 | 141.3 | 110.7 | ||||||
Purchases of petroleum products—Jonah(16) | 0.8 | 5.1 | — | ||||||
| (1) | Operating revenues earned and expenses incurred from activities with EPCO and its affiliates are considered related party transactions from February 24, 2005, through December 31, 2005, as a result of the change in ownership of the General Partner (see Note 1). |
| (2) | Includes revenues from NGL transportation on the Chaparral and Panola NGL pipelines. |
| (3) | Includes revenues from LPG transportation on the TE Products pipeline. |
| (4) | Includes other operating revenues on TE Products. |
| (5) | Substantially all of these costs were related to payroll, payroll related expenses and administrative expenses incurred in managing us and our subsidiaries. |
| (6) | Includes TCO purchases of condensate and expenses related to LSI’s use of an affiliate of EPCO as a transporter. |
| (7) | Operating revenues earned and expenses incurred from activities with DEFS and its affiliates are considered related party transactions for all periods through February 23, 2005, as a result of the change in ownership of the General Partner (see Note 1). |
| (8) | Includes LSI sales of lubrication oils and specialty chemicals and Jonah NGL sales in connection with Jonah’s Pioneer processing plant operations, which was constructed during the Phase III expansion and began operating in 2004. Amounts related to the Pioneer plant are classified as discontinued operations in the consolidated statements of income. |
| (9) | Includes revenues from NGL transportation on the Chaparral, Panola, Dean and Wilcox NGL pipelines. |
| (10) | Includes gas gathering revenues on the Jonah system. |
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
| (11) | Effective May 2001, we entered into an agreement with an affiliate of DEFS to commit to it sole utilization of our Providence, Rhode Island, terminal. We operate the terminal and provide propane loading services to an affiliate of DEFS. We recognized revenue from an affiliate of DEFS pursuant to this agreement. |
| (12) | Includes fractionation revenues and other revenues. Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into a 20-year Fractionation Agreement, under which TEPPCO Colorado receives a variable fee for all fractionated volumes delivered to DEFS. Other operating revenues also include other operating revenues on TE Products and processing and other revenues on the Jonah system. Amounts related to the Pioneer plant are classified as discontinued operations in the consolidated statements of income. |
| (13) | Includes operating costs and expenses related to DEFS managing and operating the Jonah and Val Verde systems and the Chaparral NGL pipeline on our behalf under a contractual agreement established at the time of acquisition of each asset. In connection with the change in ownership of our General Partner, we have assumed these activities. |
| (14) | Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into an Operation and Maintenance Agreement, whereby DEFS operates and maintains the fractionation facilities for TEPPCO Colorado. For these services, TEPPCO Colorado pays DEFS a set volumetric rate for all fractionated volumes delivered to DEFS. |
| (15) | Includes TCO purchases of condensate. |
| (16) | Includes Jonah purchases of natural gas in connection with Jonah’s Pioneer processing plant operations. |
At December 31, 2005, we had a receivable from EPCO and affiliates of $4.3 million related to sales and transportation services provided to EPCO and affiliates. At December 31, 2005, we had a payable to EPCO and affiliates of $9.8 million related to direct payroll, payroll related costs and other operational related charges.
At December 31, 2004, we had a receivable from DEFS and affiliates of $10.5 million related to sales and transportation services provided to DEFS and affiliates. Included in this receivable balance from DEFS and affiliates at December 31, 2004, is a gas imbalance receivable of $0.9 million. At December 31, 2004, we had a payable to DEFS and affiliates of $22.4 million related to direct payroll, payroll related costs, management fees, and other operational related charges, including those for Jonah, Chaparral and Val Verde as described above. Included in this payable balance at December 31, 2004, is a gas imbalance payable to DEFS and affiliates of $3.2 million.
From February 24, 2005 through December 31, 2005, the majority of our insurance coverage, including property, liability, business interruption, auto and directors and officers’ liability insurance, was obtained through EPCO. From February 24, 2005 through December 31, 2005, we incurred insurance expense related to premiums charged by EPCO of $9.8 million. At December 31, 2005, we had insurance reimbursement receivables due from EPCO of $1.3 million.
Through February 23, 2005, we contracted with Bison Insurance Company Limited (“Bison”), a wholly owned subsidiary of Duke Energy, for a majority of our insurance coverage, including property, liability, auto and directors and officers’ liability insurance. Through February 23, 2005 and for the years ended December 31, 2004 and 2003, we incurred insurance expense related to premiums paid to Bison of $1.2 million, $6.5 million and $5.9 million, respectively. At December 31, 2004, we had insurance reimbursement receivables due from Bison of $5.2 million.
On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3.9 million previously outstanding Class B Units held by DETTCO (see Note 11).
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
Seaway
We own a 50% ownership interest in Seaway, and the remaining 50% interest is owned by ConocoPhillips (see Note 6). We operate the Seaway assets. During the years ended December 31, 2005, 2004 and 2003, we billed Seaway $8.5 million, $7.6 million and $7.4 million, respectively, for direct payroll and payroll related expenses for operating Seaway. Additionally, for each of the years ended December 31, 2005, 2004 and 2003, we billed Seaway $2.1 million for indirect management fees for operating Seaway. At December 31, 2005 and 2004, we had payable balances to Seaway of $0.6 million and $0.5 million, respectively, for advances Seaway paid to us as operator for operating costs, including payroll and related expenses and management fees.
Centennial
TE Products has a 50% ownership interest in Centennial (see Note 6). TE Products has entered into a management agreement with Centennial to operate Centennial’s terminal at Creal Springs, Illinois, and pipeline connection in Beaumont, Texas. For each of the years ended December 31, 2005, 2004 and 2003, we recognized management fees of $0.2 million from Centennial, and actual operating expenses billed to Centennial were $3.7 million, $6.9 million and $4.4 million, respectively.
TE Products also has a joint tariff with Centennial to deliver products at TE Products’ locations using Centennial’s pipeline as part of the delivery route to connecting carriers. TE Products, as the delivering pipeline, invoices the shippers for the entire delivery rate, records only the net rate attributable to it as transportation revenues and records a liability for the amounts due to Centennial for its share of the tariff. In addition, TE Products performs ongoing construction services for Centennial and bills Centennial for labor and other costs to perform the construction. At December 31, 2005 and 2004, we had net payable balances of $1.4 million and $1.7 million, respectively, to Centennial for its share of the joint tariff deliveries and other operational related charges, partially offset by the reimbursement due to us for construction services provided to Centennial.
In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years that contains a minimum throughput requirement. For the years ended December 31, 2005, 2004 and 2003, TE Products incurred $5.9 million, $5.3 million and $3.8 million, respectively, of rental charges related to the lease of pipeline capacity on Centennial.
MB Storage
Effective January 1, 2003, TE Products entered into agreements with Louis Dreyfus to form MB Storage (see Note 6). TE Products operates the facilities for MB Storage. TE Products and MB Storage have entered into a pipeline capacity lease agreement, and for each of the years ended December 31, 2005, 2004 and 2003, TE Products recognized $0.1 million in rental revenue related to this lease agreement. During the years ended December 31, 2005, 2004 and 2003, TE Products also billed MB Storage $3.6 million, $3.2 million and $2.5 million, respectively, for direct payroll and payroll related expenses for operating MB Storage. At December 31, 2005 and 2004, TE Products had net receivable balances from MB Storage of $0.9 million and $1.3 million, respectively, for operating costs, including payroll and related expenses for operating MB Storage.
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
NOTE 8. INVENTORIES
Inventories are valued at the lower of cost (based on weighted average cost method) or market. The costs of inventories did not exceed market values at December 31, 2005 and 2004. The major components of inventories were as follows (in thousands):
| December 31, | ||||||
| 2005 | 2004 | |||||
Crude oil | $ | 3,021 | $ | 3,690 | ||
Refined products | 4,461 | 5,665 | ||||
LPGs | 7,403 | — | ||||
Lubrication oils and specialty chemicals | 5,740 | 4,002 | ||||
Materials and supplies | 8,203 | 6,135 | ||||
Other | 241 | 29 | ||||
Total | $ | 29,069 | $ | 19,521 | ||
NOTE 9. PROPERTY, PLANT AND EQUIPMENT
Major categories of property, plant and equipment for the years ended December 31, 2005 and 2004, were as follows (in thousands):
| December 31, | ||||||
| 2005 | 2004 | |||||
Land and right of way | $ | 147,064 | $ | 135,984 | ||
Line pipe and fittings | 1,434,392 | 1,344,193 | ||||
Storage tanks | 189,054 | 140,690 | ||||
Buildings and improvements | 51,596 | 41,205 | ||||
Machinery and equipment | 370,439 | 333,363 | ||||
Construction work in progress | 241,855 | 115,937 | ||||
Total property, plant and equipment | $ | 2,434,400 | $ | 2,111,372 | ||
Less accumulated depreciation and amortization | 474,332 | 407,670 | ||||
Net property, plant and equipment | $ | 1,960,068 | $ | 1,703,702 | ||
Depreciation expense, including impairment charges, on property, plant and equipment was $80.8 million, $80.7 million and $64.5 million for the years ended December 31, 2005, 2004 and 2003, respectively. During the fourth quarter of 2004, we wrote off approximately $2.1 million in assets taken out of service to depreciation expense.
In September 2005, our Todhunter facility, near Middletown, Ohio, experienced a propane release and fire at a dehydration unit within the storage facility. The facility is included in our Downstream Segment. The dehydration unit was destroyed due to the propane release and fire, and as a result, we wrote off the remaining book value of the asset of $0.8 million to depreciation and amortization expense during the third quarter of 2005.
We evaluate impairment of long-lived assets in accordance with SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets. During the third quarter of 2005, our Upstream Segment was notified by a connecting carrier that the flow of its pipeline system would be reversed, which would directly impact the viability of one of our pipeline systems. This system, located in East Texas, consists of approximately
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
45 miles of pipeline, six tanks of various sizes and other equipment and asset costs. As a result of changes to the connecting carrier, we performed an impairment test of the system and recorded a $1.8 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the estimated fair value of the system.
During the third quarter of 2005, we completed an evaluation of a crude oil system included in our Upstream Segment. The system, located in Oklahoma, consists of approximately six miles of pipelines, tanks and other equipment and asset costs. The usage of the system has declined in recent months as a result of shifting crude oil production into areas not supported by the system, and as such, it has become more economical to transport barrels by truck to our other pipeline systems. As a result, we performed an impairment test on the system and recorded a $0.8 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the estimated fair value of the system.
During the third quarter of 2004, we completed an evaluation of our marine terminal facility in the Beaumont, Texas, area. The facility consists primarily of a barge dock, a ship dock, four storage tanks and various segments of connecting pipelines and is included in our Downstream Segment. The evaluation indicated that the docks and other assets at the facility needed extensive work to continue to be commercially operational. As a result, we performed an impairment test on the entire marine facility and recorded a $4.4 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the estimated fair value of the facility.
NOTE 10. DEBT
Senior Notes
On January 27, 1998, TE Products completed the issuance of $180.0 million principal amount of 6.45% Senior Notes due 2008, and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively the “TE Products Senior Notes”). The 6.45% TE Products Senior Notes were issued at a discount of $0.3 million and are being accreted to their face value over the term of the notes. The 6.45% TE Products Senior Notes due 2008 are not subject to redemption prior to January 15, 2008. The 7.51% TE Products Senior Notes due 2028, issued at par, may be redeemed at any time after January 15, 2008, at the option of TE Products, in whole or in part, at our election at the following redemption prices (expressed in percentages of the principal amount) if redeemed during the twelve months beginning January 15 of the years indicated:
Year | Redemption Price | Year | Redemption Price | |||||
2008 | 103.755 | % | 2013 | 101.878 | % | |||
2009 | 103.380 | % | 2014 | 101.502 | % | |||
2010 | 103.004 | % | 2015 | 101.127 | % | |||
2011 | 102.629 | % | 2016 | 100.751 | % | |||
2012 | 102.253 | % | 2017 | 100.376 | % |
and thereafter at 100% of the principal amount, together in each case with accrued interest at the redemption date.
The TE Products Senior Notes do not have sinking fund requirements. Interest on the TE Products Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The TE Products Senior Notes are unsecured obligations of TE Products and rank pari passu with all other unsecured and unsubordinated
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
indebtedness of TE Products. The indenture governing the TE Products Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2005, TE Products was in compliance with the covenants of the TE Products Senior Notes.
On February 20, 2002, we completed the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount of $2.2 million and are being accreted to their face value over the term of the notes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 7.625% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2005, we were in compliance with the covenants of these Senior Notes.
On January 30, 2003, we completed the issuance of $200.0 million principal amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at a discount of $1.4 million and are being accreted to their face value over the term of the notes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 6.125% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2005, we were in compliance with the covenants of these Senior Notes.
The following table summarizes the estimated fair values of the Senior Notes as of December 31, 2005 and 2004 (in millions):
Face Value | Fair Value December 31, | ||||||||
| 2005 | 2004 | ||||||||
6.45% TE Products Senior Notes, due January 2008 | $ | 180.0 | $ | 183.7 | $ | 187.1 | |||
7.625% Senior Notes, due February 2012 | 500.0 | 552.0 | 569.6 | ||||||
6.125% Senior Notes, due February 2013 | 200.0 | 205.6 | 210.2 | ||||||
7.51% TE Products Senior Notes, due January 2028 | 210.0 | 224.1 | 225.6 | ||||||
We have entered into interest rate swap agreements to hedge our exposure to changes in the fair value on a portion of the Senior Notes discussed above (see Note 4).
Revolving Credit Facility
On April 6, 2001, we entered into a $500.0 million revolving credit facility including the issuance of letters of credit of up to $20.0 million (“Three Year Facility”). The interest rate was based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Three Year Facility contained certain restrictive financial covenant ratios. During the first quarter of 2003, we repaid $182.0 million of the outstanding balance of the Three Year Facility with proceeds from the issuance of our 6.125% Senior Notes on January 30, 2003. On June 27, 2003, we repaid the outstanding balance under the Three Year Facility with borrowings under a new credit facility, and canceled the Three Year Facility.
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
On June 27, 2003, we entered into a $550.0 million unsecured revolving credit facility with a three year term, including the issuance of letters of credit of up to $20.0 million (“Revolving Credit Facility”). The interest rate is based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Revolving Credit Facility contains certain restrictive financial covenant ratios. Restrictive covenants in the Revolving Credit Facility limit our ability to, among other things, incur additional indebtedness, make distributions in excess of Available Cash (see Note 11) and complete mergers, acquisitions and sales of assets. We borrowed $263.0 million under the Revolving Credit Facility and repaid the outstanding balance of the Three Year Facility. On October 21, 2004, we amended our Revolving Credit Facility to (i) increase the facility size to $600.0 million, (ii) extend the term to October 21, 2009, (iii) remove certain restrictive covenants, (iv) increase the available amount for the issuance of letters of credit up to $100.0 million and (v) decrease the LIBOR rate spread charged at the time of each borrowing. On February 23, 2005, we amended our Revolving Credit Facility to remove the requirement that DEFS must at all times own, directly or indirectly, 100% of our General Partner, to allow for its acquisition by DFI (see Note 1). During the second quarter of 2005, we used a portion of the proceeds from the equity offering in May 2005 to repay a portion of the Revolving Credit Facility (see Note 11). On December 13, 2005, we again amended our Revolving Credit Facility as follows:
| • | Total bank commitments increased from $600.0 million to $700.0 million. The amendment also provided that the commitments under the credit facility may be increased up to a maximum of $850.0 million upon our request, subject to lender approval and the satisfaction of certain other conditions. |
| • | The facility fee and the borrowing rate currently in effect were reduced by 0.275%. |
| • | The maturity date of the credit facility was extended from October 21, 2009, to December 13, 2010. Also under the terms of the amendment, we may request up to two, one-year extensions of the maturity date. These extensions, if requested, will become effective subject to lender approval and satisfaction of certain other conditions. |
| • | The amendment also removed the $100.0 million limit on the total amount of standby letters of credit that can be outstanding under the credit facility. |
On December 31, 2005, $405.9 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 4.9%. At December 31, 2005, we were in compliance with the covenants of this credit agreement.
The following table summarizes the principal amounts outstanding under all of our credit facilities as of December 31, 2005 and 2004 (in thousands):
| December 31, | ||||||
| 2005 | 2004 | |||||
Credit Facilities: | ||||||
Revolving Credit Facility, due December 2010 | $ | 405,900 | $ | 353,000 | ||
6.45% TE Products Senior Notes, due January 2008 | 179,937 | 179,906 | ||||
7.625% Senior Notes, due February 2012 | 498,659 | 498,438 | ||||
6.125% Senior Notes, due February 2013 | 198,988 | 198,845 | ||||
7.51% TE Products Senior Notes, due January 2028 | 210,000 | 210,000 | ||||
Total borrowings | 1,493,484 | 1,440,189 | ||||
Adjustment to carrying value associated with hedges of fair value | 31,537 | 40,037 | ||||
Total Credit Facilities | $ | 1,525,021 | $ | 1,480,226 | ||
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
Letter of Credit
At December 31, 2005, we had an $11.5 million standby letter of credit in connection with crude oil purchases in the fourth quarter of 2005. This amount will be paid during the first quarter of 2006.
NOTE 11. PARTNERS’ CAPITAL AND DISTRIBUTIONS
Equity Offerings
On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3.9 million previously outstanding Class B Units held by DETTCO. We received approximately $0.7 million in proceeds from the offering in excess of the amount needed to repurchase and retire the Class B Units.
On August 7, 2003, we sold in an underwritten public offering 5.0 million Units at $34.68 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $166.0 million. On August 19, 2003, 162,900 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on August 7, 2003. Proceeds from the over-allotment sale, net of underwriting discount, totaled $5.4 million. Approximately $53.0 million of the proceeds were used to repay indebtedness under our revolving credit facility and $21.0 million was used to fund the acquisition of the Genesis assets (see Note 5). The remaining amount was used primarily to fund revenue-generating and system upgrade capital expenditures and for general partnership purposes.
On May 5, 2005, we sold in an underwritten public offering 6.1 million Units at $41.75 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $244.5 million. On June 8, 2005, 865,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on May 5, 2005. Proceeds from the over-allotment sale, net of underwriting discount, totaled $34.7 million. The proceeds were used to reduce indebtedness under our Revolving Credit Facility, to fund revenue generating and system upgrade capital expenditures and for general partnership purposes.
Quarterly Distributions of Available Cash
We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. Pursuant to the Partnership Agreement, the General Partner receives incremental incentive cash distributions when unitholders’ cash distributions exceed certain target thresholds as follows:
| Unitholders | General Partner | |||||
Quarterly Cash Distribution per Unit: | ||||||
Up to Minimum Quarterly Distribution ($0.275 per Unit) | 98 | % | 2 | % | ||
First Target—$0.276 per Unit up to $0.325 per Unit | 85 | % | 15 | % | ||
Second Target—$0.326 per Unit up to $0.45 per Unit | 75 | % | 25 | % | ||
Over Second Target—Cash distributions greater than $0.45 per Unit | 50 | % | 50 | % |
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
The following table reflects the allocation of total distributions paid during the years ended December 31, 2005, 2004 and 2003 (in thousands, except per Unit amounts):
| Years Ended December 31, | |||||||||
| 2005 | 2004 | 2003 | |||||||
Limited Partner Units | $ | 177,917 | $ | 166,158 | $ | 145,427 | |||
General Partner Ownership Interest | 3,630 | 3,391 | 3,016 | ||||||
General Partner Incentive | 69,554 | 63,508 | 51,709 | ||||||
Total Partners’ Capital Cash Distributions Paid | 251,101 | 233,057 | 200,152 | ||||||
Class B Units | — | — | 2,346 | ||||||
Total Cash Distributions Paid | $ | 251,101 | $ | 233,057 | $ | 202,498 | |||
Total Cash Distributions Paid Per Unit | $ | 2.68 | $ | 2.64 | $ | 2.50 | |||
On February 7, 2006, we paid a cash distribution of $0.675 per Unit for the quarter ended December 31, 2005. The fourth quarter 2005 cash distribution totaled $66.9 million.
General Partner Interest
As of December 31, 2005 and 2004, we had deficit balances of $61.5 million and $35.9 million, respectively, in our General Partner’s equity account. These negative balances do not represent an asset to us and do not represent an obligation of the General Partner to contribute cash or other property to us. The General Partner’s equity account generally consists of its cumulative share of our net income less cash distributions made to it plus capital contributions that it has made to us (see our Consolidated Statements of Partners’ Capital for a detail of the General Partner’s equity account). For the years ended December 31, 2005, 2004 and 2003, the General Partner was allocated $47.6 million (representing 29.27%), $40.0 million (representing 28.85%) and $33.7 million (representing 27.65%), respectively, of our net income and received $73.2 million, $66.9 million and $54.7 million, respectively, in cash distributions.
Capital Accounts, as defined under our Partnership Agreement, are maintained for our General Partner and our limited partners. The Capital Account provisions of our Partnership Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under accounting principles generally accepted in the United States in our financial statements. Under our Partnership Agreement, the General Partner is required to make additional capital contributions to us upon the issuance of any additional Units if necessary to maintain a Capital Account balance equal to 1.999999% of the total Capital Accounts of all partners. At December 31, 2005 and 2004, the General Partner’s Capital Account balance substantially exceeded this requirement.
Net income is allocated between the General Partner and the limited partners in the same proportion as aggregate cash distributions made to the General Partner and the limited partners during the period. This is generally consistent with the manner of allocating net income under our Partnership Agreement. Net income determined under our Partnership Agreement, however, incorporates principles established for U.S. federal income tax purposes and is not comparable to net income reflected under accounting principles generally accepted in the United States in our financial statements.
Cash distributions that we make during a period may exceed our net income for the period. We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. Cash
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
distributions in excess of net income allocations and capital contributions during the years ended December 31, 2005 and 2004, resulted in a deficit in the General Partner’s equity account at December 31, 2005 and 2004. Future cash distributions that exceed net income will result in an increase in the deficit balance in the General Partner’s equity account.
According to the Partnership Agreement, in the event of our dissolution, after satisfying our liabilities, our remaining assets would be divided among our limited partners and the General Partner generally in the same proportion as Available Cash but calculated on a cumulative basis over the life of the Partnership. If a deficit balance still remains in the General Partner’s equity account after all allocations are made between the partners, the General Partner would not be required to make whole any such deficit.
NOTE 12. CONCENTRATIONS OF CREDIT RISK
Our primary market areas are located in the Northeast, Midwest and Southwest regions of the United States. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. We thoroughly analyze our customers’ historical and future credit positions prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments and guarantees.
For each of the years ended December 31, 2005, 2004 and 2003, Valero Energy Corp. accounted for 14%, 16% and 16% of our total consolidated revenues, respectively. No other single customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2005, 2004 and 2003.
The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable and accrued liabilities, other current liabilities and derivatives approximates their fair value due to their short-term nature.
NOTE 13. UNIT-BASED COMPENSATION
1994 Long Term Incentive Plan
During 1994, the Company adopted the Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan (“1994 LTIP”). The 1994 LTIP provides certain key employees with an incentive award whereby a participant is granted an option to purchase Units. These same employees are also granted a stipulated number of Performance Units, the cash value of which may be used to pay for the exercise of the respective Unit options awarded. Under the provisions of the 1994 LTIP, no more than one million options and two million Performance Units may be granted.
When our calendar year earnings per unit (exclusive of certain special items) exceeds a stated threshold, each participant receives a credit to their respective Performance Unit account equal to the earnings per unit excess multiplied by the number of Performance Units awarded. The balance in the Performance Unit account may be used to offset the cost of exercising Unit options granted in connection with the Performance Units or may be withdrawn two years after the underlying options expire, usually 10 years from the date of grant. Any unused balance previously credited is forfeited upon termination. We accrue compensation expense for the Performance Units awarded annually based upon the terms of the plan discussed above.
Under the agreement for such Unit options, the options become exercisable in equal installments over periods of one, two, and three years from the date of the grant. At December 31, 2005, all options have been fully
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
exercised. The Performance Unit account has a minimal liability balance which may be withdrawn by the participants after December 31, 2006.
A summary of Unit options granted under the terms of the 1994 LTIP is presented below:
| Options Outstanding | Options Exercisable | Exercise Range | |||||||
Unit Options: | |||||||||
Outstanding at December 31, 2002 | 90,091 | 90,091 | $ | 13.81–$25.69 | |||||
Exercised | (90,091 | ) | (90,091 | ) | $ | 13.81–$25.69 | |||
Outstanding at December 31, 2003 | — | — | |||||||
We have not granted options for any periods presented. During the year ended December 31, 2003, all remaining outstanding Unit options were exercised. For options previously outstanding, we followed the intrinsic value method for recognizing stock-based compensation expense. The exercise price of all options awarded under the 1994 LTIP equaled the market price of our Units on the date of grant. Accordingly, we recognized no compensation expense at the date of grant. Had compensation expense been determined consistent with SFAS No. 123,Accounting for Stock-Based Compensation, no compensation expense would have been recognized for the years ended December 31, 2005, 2004 and 2003.
1999 and 2002 Phantom Unit Plans
Effective September 1, 1999, the Company adopted the Texas Eastern Products Pipeline Company, LLC 1999 Phantom Unit Retention Plan (“1999 PURP”). Effective June 1, 2002, the Company adopted the Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan (“2002 PURP”). The 1999 PURP and the 2002 PURP provide key employees with incentive awards whereby a participant is granted phantom units. These phantom units are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at stated redemption dates. The fair market value of each phantom unit is equal to the closing price of a Unit as reported on the New York Stock Exchange on the redemption date.
Under the agreement for the phantom units, each participant will vest 10% of the number of phantom units initially granted under his or her award at the end of each of the first four years and will vest the final 60% at the end of the fifth year. Each participant is required to redeem their phantom units as they vest. They are also entitled to quarterly cash distributions equal to the product of the number of phantom units outstanding for the participant and the amount of the cash distribution that we paid per Unit to unitholders. We accrued compensation expense annually based upon the terms of the 1999 PURP and 2002 PURP discussed above. At December 31, 2004, we had an accrued liability balance of $1.6 million for compensation related to the 1999 PURP and 2002 PURP. Due to a change of ownership as a result of the sale of our General Partner on February 24, 2005 (see Note 1), all outstanding units under both the 1999 PURP and the 2002 PURP fully vested and were redeemed by participants. As such, there were no outstanding units at December 31, 2005 under either the 1999 PURP or the 2002 PURP.
2000 Long Term Incentive Plan
Effective January 1, 2000, the General Partner established the Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) to provide key employees incentives to achieve improvements in our financial performance. Generally, upon the close of a three-year performance period, if the participant is then still an employee of the General Partner, the participant will receive a cash payment in an
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amount equal to (1) the applicable performance percentage specified in the award multiplied by (2) the number of phantom units granted under the award multiplied by (3) the average of the closing prices of a Unit over the ten consecutive trading days immediately preceding the last day of the performance period. Generally, a participant’s performance percentage is based upon the improvement of our Economic Value Added (as defined below) during a three-year performance period over the Economic Value Added during the three-year period immediately preceding the performance period. If a participant incurs a separation from service during the performance period due to death, disability or retirement (as such terms are defined in the 2000 LTIP), the participant will be entitled to receive a cash payment in an amount equal to the amount computed as described above multiplied by a fraction, the numerator of which is the number of days that have elapsed during the performance period prior to the participant’s separation from service and the denominator of which is the number of days in the performance period. Due to a change of ownership as a result of the sale of our General Partner on February 24, 2005, all outstanding units under the 2000 LTIP for plan years 2003 and 2004 were fully vested and redeemed by participants. As such, there were no outstanding units at December 31, 2005, for awards granted for the plan years ended December 31, 2004 and 2003. At December 31, 2005, phantom units outstanding for awards granted for the plan year ended December 31, 2005, were 23,400.
Economic Value Added means our average annual EBITDA for the performance period minus the product of our average asset base and our cost of capital for the performance period. For purposes of the 2000 LTIP for plan years 2000 through 2002, EBITDA means our earnings before net interest expense, depreciation and amortization and our proportional interest in EBITDA of our joint ventures as presented in our consolidated financial statements prepared in accordance with generally accepted accounting principles, except that at his discretion the Chief Executive Officer (“CEO”) of the Company may exclude gains or losses from extraordinary, unusual or non-recurring items. For the years ended December 31, 2005, 2004 and 2003, EBITDA means, in addition to the above definition of EBITDA, earnings before other income – net. Average asset base means the quarterly average, during the performance period, of our gross value of property, plant and equipment,plus products and crude oil operating oil supply and the gross value of intangibles and equity investments. Our cost of capital is approved by our CEO at the date of award grant.
In addition to the payment described above, during the performance period, the General Partner will pay to the participant the amount of cash distributions that we would have paid to our unitholders had the participant been the owner of the number of Units equal to the number of phantom units granted to the participant under this award. We accrue compensation expense annually based upon the terms of the 2000 LTIP discussed above. At December 31, 2005 and 2004, we had an accrued liability balance of $0.7 million and $2.4 million, respectively, for compensation related to the 2000 LTIP.
2005 Phantom Unit Plan
Effective January 1, 2005, the Company adopted the Texas Eastern Products Pipeline Company, LLC 2005 Phantom Unit Plan (“2005 PURP”) to provide key employees incentives to achieve improvements in our financial performance. Generally, upon the close of a three-year performance period, if the participant is then still an employee of the General Partner, the participant will receive a cash payment in an amount equal to (1) the grantee’s vested percentage multiplied by (2) the number of phantom units granted under the award multiplied by (3) the average of the closing prices of a Unit over the ten consecutive trading days immediately preceding the last day of the performance period. Generally, a participant’s vested percentage is based upon the improvement of our EBITDA (as defined below) during a three-year performance period over the target EBITDA as defined at the beginning of each year during the three-year performance period. EBITDA means our earnings before minority interest, net interest expense, other income – net, income taxes, depreciation and amortization and our proportional interest in EBITDA of our joint ventures as presented in our consolidated financial statements
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prepared in accordance with generally accepted accounting principles, except that at his discretion, our CEO may exclude gains or losses from extraordinary, unusual or non-recurring items. At December 31, 2005, phantom units outstanding for awards granted for the plan year ended December 31, 2005, were 53,600.
In addition to the payment described above, during the performance period, the General Partner will pay to the participant the amount of cash distributions that we would have paid to our unitholders had the participant been the owner of the number of Units equal to the number of phantom units granted to the participant under this award. We accrue compensation expense annually based upon the terms of the 2005 PURP discussed above. At December 31, 2005, we had an accrued liability balance of $0.7 million for compensation related to the 2005 PURP.
NOTE 14. OPERATING LEASES
We use leased assets in several areas of our operations. Total rental expense for the years ended December 31, 2005, 2004 and 2003, was $24.0 million, $22.1 million and $18.8 million, respectively. The following table sets forth our minimum rental payments under our various operating leases for the years ending December 31 (in thousands):
2006 | $ | 19,536 | |
2007 | 17,391 | ||
2008 | 10,863 | ||
2009 | 7,682 | ||
2010 | 6,645 | ||
Thereafter | 21,544 | ||
| $ | 83,661 | ||
NOTE 15. EMPLOYEE BENEFITS
Retirement Plans
The TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”) was a non-contributory, trustee-administered pension plan. In addition, the TEPPCO Supplemental Benefit Plan (“TEPPCO SBP”) was a non-contributory, nonqualified, defined benefit retirement plan, in which certain executive officers participated. The TEPPCO SBP was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans. The benefit formula for all eligible employees was a cash balance formula. Under a cash balance formula, a plan participant accumulated a retirement benefit based upon pay credits and current interest credits. The pay credits were based on a participant’s salary, age and service. We used a December 31 measurement date for these plans.
On May 27, 2005, the TEPPCO RCBP and the TEPPCO SBP were amended. Effective May 31, 2005, participation in the TEPPCO RCBP was frozen, and no new participants were eligible to be covered by the plan after that date. Effective December 31, 2005, all plan benefits accrued were frozen, participants will not receive additional pay credits after that date, and all plan participants were 100% vested regardless of their years of service. The TEPPCO RCBP plan was terminated effective December 31, 2005, subject to IRS approval of plan termination, and plan participants will have the option to receive their benefits either through a lump sum payment in 2006 or through an annuity. For those plan participants who elect to receive an annuity, we will purchase an annuity contract from an insurance company in which the plan participant owns the annuity, absolving us of any future obligation to the participant. Participants in the TEPPCO SBP received pay credits
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through November 30, 2005, and received lump sum benefit payments in December 2005. Both the RCBP and SBP benefit payments are discussed below.
In June 2005, we recorded a curtailment charge of $0.1 million in accordance with SFAS No. 88,Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, as a result of the TEPPCO RCBP and TEPPCO SBP amendments. As of May 31, 2005, the following assumptions were changed for purposes of determining the net periodic benefit costs for the remainder of 2005: the discount rate, the long-term rate of return on plan assets, and the assumed mortality table. The discount rate was decreased from 5.75% to 5.00% to reflect rates of returns on bonds currently available to settle the liability. The expected long-term rate of return on plan assets was changed from 8% to 2% due to the movement of plan funds from equity investments into short-term money market funds. The mortality table was changed to reflect overall improvements in mortality experienced by the general population. The curtailment charge arose due to the accelerated recognition of the unrecognized prior service costs. We recorded additional settlement charges of approximately $0.2 million in the fourth quarter of 2005 relating to the TEPPCO SBP. We expect to record additional settlement charges of approximately $4.0 million in 2006 relating to the TEPPCO RCBP for any existing unrecognized losses upon the plan termination and final distribution of the assets to the plan participants.
The components of net pension benefits costs for the TEPPCO RCBP and the TEPPCO SBP for the years ended December 31, 2005, 2004 and 2003, were as follows (in thousands):
| Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
Service cost benefit earned during the year | $ | 4,393 | $ | 3,653 | $ | 3,179 | ||||||
Interest cost on projected benefit obligation | 934 | 719 | 504 | |||||||||
Expected return on plan assets | (671 | ) | (878 | ) | (604 | ) | ||||||
Amortization of prior service cost | 5 | 7 | 7 | |||||||||
Recognized net actuarial loss | 129 | 57 | 24 | |||||||||
SFAS 88 curtailment charge | 50 | — | — | |||||||||
SFAS 88 settlement charge | 194 | — | — | |||||||||
Net pension benefits costs | $ | 5,034 | $ | 3,558 | $ | 3,110 | ||||||
Other Postretirement Benefits
We provided certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis (“TEPPCO OPB”). Employees became eligible for these benefits if they met certain age and service requirements at retirement, as defined in the plans. We provided a fixed dollar contribution, which did not increase from year to year, towards retired employee medical costs. The retiree paid all health care cost increases due to medical inflation. We used a December 31 measurement date for this plan.
In May 2005, benefits provided to employees under the TEPPCO OPB were changed. Employees eligible for these benefits received them through December 31, 2005, however, effective December 31, 2005, these benefits were terminated. As a result of this change in benefits and in accordance with SFAS No. 106,Employers’ Accounting for Postretirement Benefits Other Than Pensions, we recorded a curtailment credit of approximately $1.7 million in our accumulated postretirement obligation which reduced our accumulated postretirement obligation to the total of the expected remaining 2005 payments under the TEPPCO OPB. The current employees participating in this plan were transferred to DEFS, who will continue to provide postretirement benefits to these retirees. We recorded a one-time settlement to DEFS in the third quarter of 2005 of $0.4 million for the remaining postretirement benefits.
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The components of net postretirement benefits cost for the TEPPCO OPB for the years ended December 31, 2005, 2004 and 2003, were as follows (in thousands):
| Year Ended December 31, | ||||||||||
| 2005 | 2004 | 2003 | ||||||||
Service cost benefit earned during the year | $ | 81 | $ | 165 | $ | 137 | ||||
Interest cost on accumulated postretirement benefit obligation | 69 | 153 | 137 | |||||||
Amortization of prior service cost | 53 | 126 | 126 | |||||||
Recognized net actuarial loss | 4 | 1 | — | |||||||
Curtailment credit | (1,676 | ) | — | — | ||||||
Settlement credit | (4 | ) | — | — | ||||||
Net postretirement benefits costs | $ | (1,473 | ) | $ | 445 | $ | 400 | |||
Effective June 1, 2005, the payroll functions performed by DEFS for our General Partner were transferred from DEFS to EPCO. For those employees who were receiving certain other postretirement benefits at the time of the acquisition of our General Partner by DFI, DEFS will continue to provide these benefits to those employees. Effective June 1, 2005, EPCO began providing certain other postretirement benefits to those employees who became eligible for the benefits after June 1, 2005, and will charge those benefit related costs to us. As a result of these changes, we recorded a $1.2 million reduction in our other postretirement obligation in June 2005.
We employed a building block approach in determining the long-term rate of return for plan assets. Historical markets were studied and long-term historical relationships between equities and fixed-income were preserved consistent with a widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates were evaluated before long-term capital market assumptions were determined. The long-term portfolio return was established via a building block approach with proper consideration of diversification and rebalancing. Peer data and historical returns were reviewed to check for reasonability and appropriateness.
The weighted average assumptions used to determine benefit obligations for the retirement plans and other postretirement benefit plans at December 31, 2005 and 2004, were as follows:
| Pension Benefits | Other Postretirement Benefits | |||||||||||
| 2005 | 2004 | 2005 | 2004 | |||||||||
Discount rate | 4.59 | % | 5.75 | % | 5.75 | % | 5.75 | % | ||||
Increase in compensation levels | — | 5.00 | % | — | — | |||||||
The weighted average assumptions used to determine net periodic benefit cost for the retirement plans and other postretirement benefit plans for the years ended December 31, 2005 and 2004, were as follows:
| Pension Benefits | Other Postretirement Benefits | |||||||
| 2005 | 2004 | 2005 | 2004 | |||||
Discount rate(1) | 5.75%/5.00% | 6.25% | 5.75%/5.00% | 6.25% | ||||
Increase in compensation levels | 5.00% | 5.00% | — | — | ||||
Expected long-term rate of return on plan assets(2) | 8.00%/2.00% | 8.00% | — | — | ||||
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| (1) | Expense was remeasured on May 31, 2005, as a result of TEPPCO RCBP and TEPPCO SBP amendments. The discount rate was decreased from 5.75% to 5% effective June 1, 2005, to reflect rates of returns on bonds currently available to settle the liability. |
| (2) | As a result of TEPPCO RCBP and TEPPCO SBP amendments, the expected return on assets was changed from 8% to 2% due to the movement of plan funds from equity investments into short-term money market funds, effective June 1, 2005. |
The following table sets forth our pension and other postretirement benefits changes in benefit obligation, fair value of plan assets and funded status as of December 31, 2005 and 2004 (in thousands):
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||
| 2005 | 2004 | 2005 | 2004 | |||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 15,940 | $ | 11,256 | $ | 2,964 | $ | 2,467 | ||||||||
Service cost | 4,393 | 3,653 | 81 | 165 | ||||||||||||
Interest cost | 934 | 719 | 70 | 153 | ||||||||||||
Actuarial loss | 2,740 | 572 | 76 | 205 | ||||||||||||
Retiree contributions | — | — | 64 | 60 | ||||||||||||
Benefits paid | (910 | ) | (260 | ) | (80 | ) | (86 | ) | ||||||||
Impact of curtailment | (986 | ) | — | (3,575 | ) | — | ||||||||||
Settlement | — | — | 400 | — | ||||||||||||
Benefit obligation at end of year | $ | 22,111 | $ | 15,940 | $ | — | $ | 2,964 | ||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | $ | 14,969 | $ | 10,921 | $ | — | $ | — | ||||||||
Actual return on plan assets | 20 | 808 | — | — | ||||||||||||
Retiree contributions | — | — | 64 | 60 | ||||||||||||
Employer contributions | 9,025 | 3,500 | 16 | 26 | ||||||||||||
Benefits paid | (910 | ) | (260 | ) | (80 | ) | (86 | ) | ||||||||
Fair value of plan assets at end of year | $ | 23,104 | $ | 14,969 | $ | — | $ | — | ||||||||
Reconciliation of funded status | ||||||||||||||||
Funded status | $ | 994 | $ | (971 | ) | $ | — | $ | (2,964 | ) | ||||||
Unrecognized prior service cost | — | 33 | — | 1,003 | ||||||||||||
Unrecognized actuarial loss | 4,067 | 2,006 | — | 472 | ||||||||||||
Net amount recognized | $ | 5,061 | $ | 1,068 | $ | — | $ | (1,489 | ) | |||||||
We estimate the following benefit payments, which reflect expected future service, as appropriate, will be paid (in thousands):
| Pension Benefits | Other Postretirement Benefits | |||||
2006 | $ | 22,360 | $ | — | ||
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Plan Assets
We employed a total return investment approach whereby a mix of equities and fixed income investments were used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance was established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contained a diversified blend of equity and fixed-income investments. Furthermore, equity investments were diversified across U.S. and non-U.S. stocks, both growth and value equity style, and small, mid and large capitalizations. Investment risk and return parameters were reviewed and evaluated periodically to ensure compliance with stated investment objectives and guidelines. This comprehensive review incorporated investment portfolio performance, annual liability measurements and periodic asset/liability studies.
The following table sets forth the weighted average asset allocations for the retirement plans and other postretirement benefit plans as of December 31, 2005 and 2004, by asset category (in thousands):
| December 31, | ||||||
Asset Category | 2005 | 2004 | ||||
Equity securities | — | 63 | % | |||
Debt securities | — | 35 | % | |||
Other (money market and cash) | 100 | % | 2 | % | ||
Total | 100 | % | 100 | % | ||
We do not expect to make further contributions to our retirement plans and other postretirement benefit plans in 2006.
Other Plans
DEFS also sponsored an employee savings plan, which covered substantially all employees. Effective February 24, 2005, in conjunction with the change in ownership of our General Partner, our participation in this plan ended. Plan contributions on behalf of the Company of $0.9 million, $3.5 million and $3.2 million were recognized for the period January 1, 2005 through February 23, 2005, and during the years ended December 31, 2004 and 2003, respectively.
NOTE 16. COMMITMENTS AND CONTINGENCIES
Litigation
In the fall of 1999 and on December 1, 2000, the General Partner and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, styledRyan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al.(including the General Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et al.(including the General Partner and Partnership).In both cases, the plaintiffs contend, among other things, that we and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water. They further contend that the release caused damages to the plaintiffs. In their complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. On January 27, 2005, we entered into Release and Settlement Agreements with the McCleery plaintiffs and the Richards plaintiffs dismissing all of these plaintiffs’ claims on terms that did not have a material adverse effect on our financial position, results of operations or cash flows. Although we did not settle with all plaintiffs and we therefore remain named parties in
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theRyan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. action, a co-defendant has agreed to indemnify us for all remaining claims asserted against us. Consequently, we do not believe that the outcome of these remaining claims will have a material adverse effect on our financial position, results of operations or cash flows.
On December 21, 2001, TE Products was named as a defendant in a lawsuit in the 10th Judicial District, Natchitoches Parish, Louisiana, styledRebecca L. Grisham et al. v. TE Products Pipeline Company, Limited Partnership. In this case, the plaintiffs contend that our pipeline, which crosses the plaintiffs’ property, leaked toxic products onto their property and, consequently caused damages to them. We have filed an answer to the plaintiffs’ petition denying the allegations, and we are defending ourselves vigorously against the lawsuit. The plaintiffs have not stipulated the amount of damages they are seeking in the suit; however, this case is covered by insurance. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.
On April 2, 2003, Centennial was served with a petition in a matter styledAdams, et al. v. Centennial Pipeline Company LLC, et al. This matter involves approximately 2,000 plaintiffs who allege that over 200 defendants, including Centennial, generated, transported, and/or disposed of hazardous and toxic waste at two sites in Bayou Sorrell, Louisiana, an underground injection well and a landfill. The plaintiffs allege personal injuries, allergies, birth defects, cancer and death. The underground injection well has been in operation since May 1976. Based upon current information, Centennial appears to be ade minimis contributor, having used the disposal site during the two month time period of December 2001 to January 2002. Marathon has been handling this matter for Centennial under its operating agreement with Centennial. TE Products has a 50% ownership interest in Centennial. On November 30, 2004, the court approved a class settlement. The time period for parties to appeal this settlement expired in March 2005, and the class settlement became final. The terms of the settlement did not have a material adverse effect on our financial position, results of operations or cash flows.
In May 2003, the General Partner was named as a defendant in a lawsuit styledJohn R. James, et al. v. J Graves Insulation Company, et al. as filed in the first Judicial District Court, Caddo Parish, Louisiana. There are numerous plaintiffs identified in the action that are alleged to have suffered damages as a result of alleged exposure to asbestos-containing products and materials. According to the petition and as a result of a preliminary investigation, the General Partner believes that the only claim asserted against it results from one individual for the period from July 1971 through June 1972, who is alleged to have worked on a facility owned by the General Partner’s predecessor. This period represents a small portion of the total alleged exposure period from January 1964 through December 2001 for this individual. The individual’s claims involve numerous employers and alleged job sites. The General Partner has been unable to confirm involvement by the General Partner or its predecessors with the alleged location, and it is uncertain at this time whether this case is covered by insurance. Discovery is planned, and the General Partner intends to defend itself vigorously against this lawsuit. The plaintiffs have not stipulated the amount of damages that they are seeking in this suit. We are obligated to reimburse the General Partner for any costs it incurs related to this lawsuit. We cannot estimate the loss, if any, associated with this pending lawsuit. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.
On August 5, 2005, we were named as a third-party defendant in a matter styledConocoPhillips, et al. v. BP Amoco Seaway Products Pipeline Companyas filed in the 55th Judicial District of Harris County, Texas. ConocoPhillips alleges a right to indemnity from BP Amoco Seaway Products Pipeline Company (“BP Amoco”) for tax liability incurred by ConocoPhillips as a result of the reverse merger of Seaway Pipeline Company (the “Original Seaway Partnership”). The reverse merger of the Original Seaway Partnership was undertaken in preparation for our purchase of ARCO Pipe Line Company pursuant to the Amended and Restated Purchase
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Agreement (the “Purchase Agreement”) dated May 10, 2000, between us and Atlantic Richfield Company. BP Amoco has claimed a right to indemnity from us under the Purchase Agreement should BP Amoco have any indemnity liability to ConocoPhillips. ConocoPhillips alleges the income tax liability to be approximately $4.0 million. On January 20, 2006, we entered into a settlement agreement with BP Amoco dismissing and resolving all of BP Amoco’s claims. The terms of the settlement did not have a material adverse effect on our financial position, results of operations or cash flows.
In 1991, we were named as a defendant in a matter styledJimmy R. Green, et al. v. Cities Service Refinery, et al.as filed in the 26th Judicial District Court of Bossier Parish, Louisiana. The plaintiffs in this matter reside or formerly resided on land that was once the site of a refinery owned by one of our co-defendants. The former refinery is located near our Bossier City facility. Plaintiffs have claimed personal injuries and property damage arising from alleged contamination of the refinery property. The plaintiffs have recently pursued certification as a class and have significantly increased their demand to approximately $175.0 million. This revised demand includes amounts for environmental restoration not previously claimed by the plaintiffs. We have never owned any interest in the refinery property made the basis of this action, and we do not believe that we contributed to any alleged contamination of this property. While we cannot predict the ultimate outcome, we do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.
In addition to the litigation discussed above, we have been, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. We believe that the outcome of these lawsuits and other proceedings will not individually or in the aggregate have a future material adverse effect on our consolidated financial position, results of operations or cash flows.
Regulatory Matters
Our operations are subject to federal, state and local laws and regulations governing the discharge of materials into the environment and various safety matters. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of injunctions delaying or prohibiting certain activities and the need to perform investigatory and remedial activities. We believe our operations have been and are in material compliance with applicable environmental and safety laws and regulations, and that compliance with existing environmental laws and regulations are not expected to have a material adverse effect on our competitive position, financial positions, results of operations or cash flows. However, risks of significant costs and liabilities are inherent in pipeline operations, and we cannot assure that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental and safety laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. At December 31, 2005 and 2004, we have an accrued liability of $2.4 million and $5.0 million, respectively, related to sites requiring environmental remediation activities.
On March 26, 2004, a decision inARCO Products Co., et al. v. SFPP, Docket OR96-2-000, was issued by the FERC, which made several significant determinations with respect to finding “changed circumstances” under the Energy Policy Act of 1992 (“EP Act”). The decision largely clarifies, but does not fully quantify, the standard required for a complainant to demonstrate that an oil pipeline’s rates are no longer subject to the rate protection of the EP Act by demonstrating that a substantial change in circumstances has occurred since 1992 with respect to the basis of the rates being challenged. In the decision, the FERC found that a limited number of rate elements will significantly affect the economic basis for a pipeline company’s rates. The elements identified in the
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Notes to Consolidated Financial Statements — Continued
decision are volume changes, allowed total return and total cost-of-service (including major cost elements such as rate base, tax rates and tax allowances, among others). The FERC did reject, however, the use of changes in tax rates and income tax allowances as stand-alone factors. Judicial review of that decision, which has been sought by a number of parties to the case, is currently pending before the U.S. Court of Appeals for the District of Columbia Circuit. We have not yet determined the impact, if any, that the decision, if it is ultimately upheld, would have on our rates if they were reviewed under the criteria of this decision.
On July 20, 2004, the District of Columbia Circuit issued an opinion inBP West Coast Products LLC v. FERC. In reviewing a series of orders involving SFPP, L.P., the court held among other things that the FERC had not adequately justified its policy of providing an oil pipeline limited partnership with an income tax allowance equal to the proportion of its income attributable to partnership interests owned by corporate partners. Under the FERC’s initial ruling, SFPP, L.P. was permitted an income tax allowance on its cost-of-service filing for the percentage of its net operating (pre-tax) income attributable to partnership units held by corporations, and was denied an income tax allowance equal to the percentage attributable to partnership units held by non-corporate partners. The court remanded the case back to the FERC for further review. As a result of the court’s remand, on May 4, 2005, the FERC issued its Policy Statement on Income Tax Allowances, which permits regulated partnerships, limited liability companies and other pass-through entities an income tax allowance on their income attributable to any owner that has an actual or potential income tax liability on that income, regardless whether the owner is an individual or corporation. If there is more than one level of pass-through entities, the regulated company income must be traced to where the ultimate tax liability lies. The Policy Statement is to be applied in individual cases, and the regulated entity bears the burden of proof to establish the tax status of its owners. On December 16, 2005, the FERC issued the first of those decisions, in an order involving SFPP (the “SFPP Order”). The SFPP Order confirmed that an MLP is entitled to a tax allowance with respect to partnership income for which there is an “actual or potential income tax liability” and determined that a unitholder that is required to file a Form 1040 or Form 1120 tax return that includes partnership income or loss is presumed to have an actual or potential income tax liability sufficient to support a tax allowance on that partnership income. The FERC also established certain other presumptions, including that corporate unitholders are presumed to be taxed at the maximum corporate tax rate of 35% while individual unitholders (and certain other types of unitholders taxed like individuals) are presumed to be taxed at a 28% tax rate. The SFPP Order remains subject to further administrative proceedings (including compliance filings by SFPP and possible rehearing requests), as well as potential judicial review. The ultimate outcome of the FERC’s inquiry on income tax allowance should not affect our current rates and rate structure because our rates are not based on cost-of-service methodology. However, the outcome of the income tax allowance would become relevant to us should we (i) elect in the future to use cost-of-service to support our rates, or (ii) be required to use such methodology to defend our indexed rates.
In 1994, the Louisiana Department of Environmental Quality (“LDEQ”) issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this contamination. Effective March 2004, we executed an access agreement with an adjacent industrial landowner who is located upgradient of the Arcadia facility. This agreement enables the landowner to proceed with remediation activities at our Arcadia facility for which it has accepted shared responsibility. At December 31, 2005, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program proposed to the LDEQ will have a future material adverse effect on our financial position, results of operations or cash flows.
On March 17, 2003, we experienced a release of 511 barrels of jet fuel from a storage tank at our Blue Island terminal located in Cook County, Illinois. As a result of the release, we have entered into an Agreed Order
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Notes to Consolidated Financial Statements — Continued
with the State of Illinois, which required us to conduct an environmental investigation. At this time, we have complied with the terms of the Agreed Order, and the results of the environmental investigation indicated there were no soil or groundwater impacts from the release. On August 30, 2005, a final settlement was reached with the State of Illinois. The settlement included the payment of a civil penalty of $0.1 million and the requirement that we make certain modifications to the equipment of the facility, none of which are expected to have a material adverse effect on our financial position, results of operations or cash flows.
On July 22, 2004, we experienced a release of approximately 12 barrels of jet fuel from a sump at our Lebanon, Ohio, terminal. The released jet fuel was contained within a storm water retention pond located on the terminal property. Six migratory waterfowl were affected by the jet fuel and were subsequently euthanized by or at the request of the United States Fish and Wildlife Service (“USFWS”). On October 1, 2004, the USFWS served us with a Notice of Violation, alleging that we violated 16 USC 703 of the Migratory Bird Treaty Act for the “take[ing] of migratory birds by illegal methods.” On February 7, 2005, we entered into a Memorandum of Understanding with the USFWS, settling all aspects of this matter. The terms of this settlement did not have a material effect on our financial position, results of operations or cash flows.
On July 27, 2004, we received notice from the United States Department of Justice (“DOJ”) of its intent to seek a civil penalty against us related to our November 21, 2001, release of approximately 2,575 barrels of jet fuel from our 14-inch diameter pipeline located in Orange County, Texas. The DOJ, at the request of the Environmental Protection Agency, is seeking a civil penalty against us for alleged violations of the Clean Water Act (“CWA”) arising out of this release. We are in discussions with the DOJ regarding this matter and have responded to its request for additional information. The maximum statutory penalty proposed by the DOJ for this alleged violation of the CWA is $2.1 million. We do not expect any civil penalty to have a material adverse effect on our financial position, results of operations or cash flows.
On September 18, 2005, a propane release and fire occurred at our Todhunter facility, near Middletown, Ohio. The incident resulted in the death of one of our employees. There were no other injuries. On or about February 22, 2006, we received verbal notification from a representative of the Occupational Safety and Health Administration that they intend to serve us with a citation arising out of this incident. At this time, we have not received any citation, and we cannot predict with certainty the amount of any fine or penalty associated with any such citation; however, we do not expect any fine or penalty to have a material adverse effect on our financial position, results of operations or cash flows.
Rates of interstate petroleum products and crude oil pipeline companies, like us, are currently regulated by the FERC primarily through an index methodology, which allows a pipeline to change its rates based on the change from year to year in the Producer Price Index for finished goods (“PPI Index”). Effective as of February 24, 2003, FERC Order on Remand modified the PPI Index from PPI—1% to PPI. On April 22, 2003, several shippers filed a petition in the United States Court of Appeals for the District of Columbia Circuit (the “Court”),Flying J. Inc,. Lion Oil Company, Sinclair Oil Corporation and Tesoro Refining and Marketing Company vs. Federal Energy Regulatory Commission; Docket No. 03-1107, seeking a review of whether the FERC’s adoption of the PPI Index was reasonable and supported by the evidence. On April 9, 2004, the Court handed down a decision denying the shippers’ petition for review, stating the shippers failed to establish that any of the FERC’s methodological choices (or combination of choices) were both erroneous and harmful.
As an alternative to using the PPI Index, interstate petroleum products and crude oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings (“Market-Based Rates”) or agreements between shippers and petroleum products and crude oil pipeline companies that the rate is acceptable.
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Notes to Consolidated Financial Statements — Continued
Other
Centennial entered into credit facilities totaling $150.0 million, and as of December 31, 2005, $150.0 million was outstanding under those credit facilities. TE Products and Marathon have each guaranteed one-half of the repayment of Centennial’s outstanding debt balance (plus interest) under a long-term credit agreement, which expires in 2024, and a short-term credit agreement, which expires in 2007. The guarantees arose in order for Centennial to obtain adequate financing, and the proceeds of the credit agreements were used to fund construction and conversion costs of its pipeline system. Prior to the expiration of the long-term credit agreement, TE Products could be relinquished from responsibility under the guarantee should Centennial meet certain financial tests. If Centennial defaults on its outstanding balance, the estimated maximum potential amount of future payments for TE Products and Marathon is $75.0 million each at December 31, 2005.
TE Products, Marathon and Centennial have entered into a limited cash call agreement, which allows each member to contribute cash in lieu of Centennial procuring separate insurance in the event of a third-party liability arising from a catastrophic event. There is an indefinite term for the agreement and each member is to contribute cash in proportion to its ownership interest, up to a maximum of $50.0 million each. As a result of the catastrophic event guarantee, TE Products has recorded a $4.6 million obligation, which represents the present value of the estimated amount that we would have to pay under the guarantee. If a catastrophic event were to occur and we were required to contribute cash to Centennial, contributions exceeding our deductible might be covered by our insurance.
One of our subsidiaries, TCO, has entered into master equipment lease agreements with finance companies for the use of various equipment. We have guaranteed the full and timely payment and performance of TCO’s obligations under the agreements. Generally, events of default would trigger our performance under the guarantee. The maximum potential amount of future payments under the guarantee is not estimable, but would include base rental payments for both current and future equipment, stipulated loss payments in the event any equipment is stolen, damaged, or destroyed and any future indemnity payments. We carry insurance coverage that may offset any payments required under the guarantees.
On February 24, 2005, the General Partner was acquired from DEFS by DFI. The General Partner owns a 2% general partner interest in us and is the general partner of the Partnership. On March 11, 2005, the Bureau of Competition of the Federal Trade Commission (“FTC”) delivered written notice to DFI’s legal advisor that it was conducting a non-public investigation to determine whether DFI’s acquisition of the General Partner may substantially lessen competition. The General Partner is cooperating fully with this investigation.
Substantially all of the petroleum products that we transport and store are owned by our customers. At December 31, 2005, TCTM and TE Products had approximately 4.0 million barrels and 22.5 million barrels, respectively, of products in their custody that was owned by customers. We are obligated for the transportation, storage and delivery of such products on behalf of our customers. We maintain insurance adequate to cover product losses through circumstances beyond our control.
We carry insurance coverage consistent with the exposures associated with the nature and scope of our operations. Our current insurance coverage includes (1) commercial general liability insurance for liabilities to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation 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, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from earthquake, flood damage and business interruption/extra expense. For select assets, we also carry pollution
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TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
liability insurance that provides coverage for historical and gradual pollution events. All coverages are subject to certain deductibles, limits or sub-limits and policy terms and conditions.
We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are commensurate with the nature and scope of our operations. The cost of our general insurance coverages has increased over the past year reflecting the changing conditions of the insurance markets. These insurance policies, except for the pollution liability policies, are through EPCO (see Note 7).
NOTE 17. SEGMENT INFORMATION
We have three reporting segments:
| • | Our Downstream Segment, which is engaged in the transportation and storage of refined products, LPGs and petrochemicals; |
| • | Our Upstream Segment, which is engaged in the gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals; and |
| • | Our Midstream Segment, which is engaged in the gathering of natural gas, fractionation of NGLs and transportation of NGLs. |
The amounts indicated below as “Partnership and Other” relate primarily to intersegment eliminations and assets that we hold that have not been allocated to any of our reporting segments.
Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. The two largest operating expense items of the Downstream Segment are labor and electric power. We generally realize higher revenues during the first and fourth quarters of each year since our operations are somewhat seasonal. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand for propane, a major fuel for residential heating. Our Downstream Segment also includes the results of operations of the northern portion of the Dean Pipeline, which transports, refinery grade propylene from Mont Belvieu to Point Comfort, Texas. Our Downstream Segment also includes our equity investments in Centennial and MB Storage (see Note 6).
Our Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals, principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Marketing operations consist primarily of aggregating purchased crude oil along our pipeline systems, or from third party pipeline systems, and arranging the necessary transportation logistics for the ultimate sale of the crude oil to local refineries, marketers or other end users. Our Upstream Segment also includes our equity investment in Seaway. Seaway consists of large diameter pipelines that transport crude oil from Seaway’s marine terminals on the U.S. Gulf Coast to Cushing, Oklahoma, a crude oil distribution point for the central United States, and to refineries in the Texas City and Houston areas.
Our Midstream Segment revenues are earned from the fractionation of NGLs in Colorado, transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and a pipeline system (Chaparral) from West Texas and New Mexico to Mont Belvieu; the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, and the gathering of CBM and conventional natural gas in the San Juan Basin in New Mexico and Colorado, through Val Verde. On March 31, 2006, we sold our ownership
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Notes to Consolidated Financial Statements — Continued
interest in the Jonah Pioneer silica gel natural gas processing plant located near Opal, Wyoming to an affiliate of Enterprise for $38.0 million in cash (see Note 5 in the Notes to the Consolidated Financial Statements). Operating results of the Pioneer plant for the years ended December 31, 2005 and 2004 are shown as discontinued operations.
The tables below include financial information by reporting segment for the years ended December 31, 2005, 2004 and 2003 (in thousands):
| Year Ended December 31, 2005 | ||||||||||||||||||||||||
| Downstream Segment | Upstream Segment | Midstream Segment | Segments Total | Partnership and Other | Consolidated | |||||||||||||||||||
Sales of petroleum products | $ | — | $ | 8,062,131 | $ | — | $ | 8,062,131 | $ | (323 | ) | $ | 8,061,808 | |||||||||||
Operating revenues | 287,191 | 48,108 | 211,171 | 546,470 | (3,244 | ) | 543,226 | |||||||||||||||||
Purchases of petroleum products | — | 7,989,682 | — | 7,989,682 | (3,244 | ) | 7,986,438 | |||||||||||||||||
Operating expenses, including power | 159,784 | 70,340 | 58,701 | 288,825 | (323 | ) | 288,502 | |||||||||||||||||
Depreciation and amortization expense | 39,403 | 17,161 | 54,165 | 110,729 | — | 110,729 | ||||||||||||||||||
Gains on sales of assets | (139 | ) | (118 | ) | (411 | ) | (668 | ) | — | (668 | ) | |||||||||||||
Operating income | 88,143 | 33,174 | 98,716 | 220,033 | — | 220,033 | ||||||||||||||||||
Equity earnings (losses) | (2,984 | ) | 23,078 | — | 20,094 | — | 20,094 | |||||||||||||||||
Other income, net | 755 | 156 | 224 | 1,135 | — | 1,135 | ||||||||||||||||||
Earnings before interest from continuing operations | 85,914 | 56,408 | 98,940 | 241,262 | — | 241,262 | ||||||||||||||||||
Discontinued operations | — | — | 3,150 | 3,150 | — | 3,150 | ||||||||||||||||||
Earnings before interest | $ | 85,914 | $ | 56,408 | $ | 102,090 | $ | 244,412 | $ | — | $ | 244,412 | ||||||||||||
| Year Ended December 31, 2004 | |||||||||||||||||||||||
| Downstream Segment | Upstream Segment | Midstream Segment | Segments Total | Partnership and Other | Consolidated | ||||||||||||||||||
| (as restated) | (as restated) | (as restated) | (as restated) | ||||||||||||||||||||
Sales of petroleum products | $ | — | $ | 5,426,832 | $ | — | $ | 5,426,832 | $ | — | $ | 5,426,832 | |||||||||||
Operating revenues | 279,400 | 49,163 | 195,902 | 524,465 | (3,207 | ) | 521,258 | ||||||||||||||||
Purchases of petroleum products | — | 5,370,234 | — | 5,370,234 | (3,207 | ) | 5,367,027 | ||||||||||||||||
Operating expenses, including power | 165,528 | 60,893 | 58,967 | 285,388 | — | 285,388 | |||||||||||||||||
Depreciation and amortization expense | 43,135 | 13,130 | 56,019 | 112,284 | — | 112,284 | |||||||||||||||||
Gains on sales of assets | (526 | ) | (527 | ) | — | (1,053 | ) | — | (1,053 | ) | |||||||||||||
Operating income | 71,263 | 32,265 | 80,916 | 184,444 | — | 184,444 | |||||||||||||||||
Equity earnings (losses) | (6,544 | ) | 28,692 | — | 22,148 | — | 22,148 | ||||||||||||||||
Other income, net | 787 | 406 | 127 | 1,320 | — | 1,320 | |||||||||||||||||
Earnings before interest from continuing operations | 65,506 | 61,363 | 81,043 | 207,912 | — | 207,912 | |||||||||||||||||
Discontinued operations | — | — | 2,689 | 2,689 | — | 2,689 | |||||||||||||||||
Earnings before interest | $ | 65,506 | $ | 61,363 | $ | 83,732 | $ | 210,601 | $ | — | $ | 210,601 | |||||||||||
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Notes to Consolidated Financial Statements — Continued
| Year Ended December 31, 2003 | |||||||||||||||||||||||
| Downstream Segment | Upstream Segment | Midstream Segment | Segments Total | Partnership and Other | Consolidated | ||||||||||||||||||
| (as restated) | (as restated) | (as restated) | (as restated) | ||||||||||||||||||||
Sales of petroleum products | $ | — | $ | 3,766,651 | $ | — | $ | 3,766,651 | $ | — | $ | 3,766,651 | |||||||||||
Operating revenues | 266,427 | 39,564 | 185,105 | 491,096 | (1,915 | ) | 489,181 | ||||||||||||||||
Purchases of petroleum products | — | 3,713,122 | — | 3,713,122 | (1,915 | ) | 3,711,207 | ||||||||||||||||
Operating expenses, including power | 151,103 | 57,314 | 47,020 | 255,437 | — | 255,437 | |||||||||||||||||
Depreciation and amortization expense | 31,620 | 11,311 | 57,797 | 100,728 | — | 100,728 | |||||||||||||||||
Gain on sale of assets | — | (3,948 | ) | — | (3,948 | ) | — | (3,948 | ) | ||||||||||||||
Operating income | 83,704 | 28,416 | 80,288 | 192,408 | — | 192,408 | |||||||||||||||||
Equity earnings (losses) | (7,384 | ) | 20,258 | — | 12,874 | — | 12,874 | ||||||||||||||||
Other income, net | 226 | 306 | 289 | 821 | (73 | ) | 748 | ||||||||||||||||
Earnings before interest | $ | 76,546 | $ | 48,980 | $ | 80,577 | $ | 206,103 | $ | (73 | ) | $ | 206,030 | ||||||||||
The following table provides the total assets, capital expenditures and significant non-cash investing activities for each segment as of and for the years ended December 31, 2005, 2004 and 2003 (in thousands):
| Downstream Segment | Upstream Segment | Midstream Segment | Segments Total | Partnership and Other | Consolidated | ||||||||||||||
December 31, 2005: | |||||||||||||||||||
Total assets | $ | 1,056,217 | $ | 1,353,492 | $ | 1,280,548 | $ | 3,690,257 | $ | (9,719 | ) | $ | 3,680,538 | ||||||
Capital expenditures | 58,609 | 40,954 | 119,837 | 219,400 | 1,153 | 220,553 | |||||||||||||
Non-cash investing activities | 1,429 | — | — | 1,429 | — | 1,429 | |||||||||||||
December 31, 2004 (as restated): | |||||||||||||||||||
Total assets | $ | 959,042 | $ | 1,069,007 | $ | 1,184,184 | $ | 3,212,233 | $ | (25,949 | ) | $ | 3,186,284 | ||||||
Capital expenditures | 80,930 | 37,448 | 37,677 | 156,055 | 694 | 156,749 | |||||||||||||
Capital expenditures for discontinued operations | — | — | 7,398 | 7,398 | — | 7,398 | |||||||||||||
December 31, 2003 (as restated): | |||||||||||||||||||
Total assets | $ | 911,184 | $ | 833,723 | $ | 1,194,844 | $ | 2,939,751 | $ | (5,271 | ) | $ | 2,934,480 | ||||||
Capital expenditures | 59,061 | 13,427 | 54,072 | 126,560 | 147 | 126,707 | |||||||||||||
Capital expenditures for discontinued operations | — | — | 13,810 | 13,810 | — | 13,810 | |||||||||||||
Non-cash investing activities | 61,042 | — | — | 61,042 | — | 61,042 | |||||||||||||
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TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
The following table reconciles the segments total earnings before interest to consolidated net income for the three years ended December 31, 2005, 2004 and 2003 (in thousands):
| Years Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
| (as restated) | (as restated) | |||||||||||
Earnings before interest | $ | 244,412 | $ | 210,601 | $ | 206,030 | ||||||
Interest expense—net | (81,861 | ) | (72,053 | ) | (84,250 | ) | ||||||
Net income | $ | 162,551 | $ | 138,548 | $ | 121,780 | ||||||
NOTE 18. COMPREHENSIVE INCOME
SFAS No. 130,Reporting Comprehensive Income requires certain items such as foreign currency translation adjustments, minimum pension liability adjustments and unrealized gains and losses on certain investments to be reported in a financial statement. As of and for the year ended December 31, 2005, the components of comprehensive income were due to crude oil hedges. The crude oil hedges mature in December 2006. While the crude oil hedges are in effect, changes in the fair values of the crude oil hedges, to the extent the hedges are effective, are recognized in other comprehensive income until they are recognized in net income in future periods. As of and for the year ended December 31, 2004, the components of comprehensive income were due to the interest rate swap related to our variable rate revolving credit facility, which was designated as a cash flow hedge. The interest rate swap matured in April 2004. While the interest rate swap was in effect, changes in the fair value of the cash flow hedge, to the extent the hedge was effective, were recognized in other comprehensive income until the hedge interest costs were recognized in net income.
The accumulated balance of other comprehensive income related to our cash flow hedges is as follows (in thousands):
Balance at December 31, 2002 (as restated) | $ | (20,055 | ) | |
Reclassification due to discontinued portion of cash flow hedge | 989 | |||
Transferred to earnings | 14,417 | |||
Change in fair value of cash flow hedge | 1,747 | |||
Balance at December 31, 2003 (as restated) | $ | (2,902 | ) | |
Transferred to earnings | 2,939 | |||
Change in fair value of cash flow hedge | (37 | ) | ||
Balance at December 31, 2004 (as restated) | $ | — | ||
Changes in fair values of crude oil cash flow hedges | 11 | |||
Balance at December 31, 2005 | $ | 11 | ||
NOTE 19. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Our significant operating subsidiaries, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P., have issued unconditional guarantees of our debt securities. The guarantees are full, unconditional, and joint and several. TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. are collectively referred to as the “Guarantor Subsidiaries.”
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TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
The following supplemental condensed consolidating financial information reflects our separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of our other non-guarantor subsidiaries, the combined consolidating adjustments and eliminations and our consolidated accounts for the dates and periods indicated. For purposes of the following consolidating information, our investments in our subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for under the equity method of accounting.
| December 31, 2005 | ||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | ||||||||||||
| (in thousands) | ||||||||||||||||
Assets | ||||||||||||||||
Current assets | $ | 40,977 | $ | 107,692 | $ | 789,486 | $ | (39,026 | ) | $ | 899,129 | |||||
Property, plant and equipment—net | — | 1,335,724 | 624,344 | — | 1,960,068 | |||||||||||
Equity investments | 1,201,388 | 461,741 | 202,343 | (1,505,816 | ) | 359,656 | ||||||||||
Intercompany notes receivable | 1,134,093 | — | — | (1,134,093 | ) | — | ||||||||||
Intangible assets | — | 345,005 | 31,903 | — | 376,908 | |||||||||||
Other assets | 5,532 | 22,170 | 57,075 | — | 84,777 | |||||||||||
Total assets | $ | 2,381,990 | $ | 2,272,332 | $ | 1,705,151 | $ | (2,678,935 | ) | $ | 3,680,538 | |||||
Liabilities and partners’ capital | ||||||||||||||||
Current liabilities | $ | 43,236 | $ | 140,743 | $ | 793,683 | $ | (40,451 | ) | $ | 937,211 | |||||
Long-term debt | 1,135,973 | 389,048 | — | — | 1,525,021 | |||||||||||
Intercompany notes payable | — | 635,263 | 498,832 | (1,134,095 | ) | — | ||||||||||
Other long term liabilities | 1,422 | 14,564 | 950 | — | 16,936 | |||||||||||
Total partners’ capital | 1,201,359 | 1,092,714 | 411,686 | (1,504,389 | ) | 1,201,370 | ||||||||||
Total liabilities and partners’ capital | $ | 2,381,990 | $ | 2,272,332 | $ | 1,705,151 | $ | (2,678,935 | ) | $ | 3,680,538 | |||||
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TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
| December 31, 2004 (as restated) | ||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | ||||||||||||
| (in thousands) | ||||||||||||||||
Assets | ||||||||||||||||
Current assets | $ | 44,125 | $ | 85,992 | $ | 576,365 | $ | (62,928 | ) | $ | 643,554 | |||||
Property, plant and equipment—net | — | 1,211,312 | 492,390 | — | 1,703,702 | |||||||||||
Equity investments | 1,011,131 | 420,343 | 202,326 | (1,270,493 | ) | 363,307 | ||||||||||
Intercompany notes receivable | 1,084,034 | — | — | (1,084,034 | ) | — | ||||||||||
Intangible assets | — | 372,621 | 34,737 | — | 407,358 | |||||||||||
Other assets | 5,980 | 22,183 | 40,200 | — | 68,363 | |||||||||||
Total assets | $ | 2,145,270 | $ | 2,112,451 | $ | 1,346,018 | $ | (2,417,455 | ) | $ | 3,186,284 | |||||
Liabilities and partners’ capital | ||||||||||||||||
Current liabilities | $ | 45,255 | $ | 142,513 | $ | 556,474 | $ | (62,930 | ) | $ | 681,312 | |||||
Long-term debt | 1,086,909 | 393,317 | — | — | 1,480,226 | |||||||||||
Intercompany notes payable | — | 676,993 | 407,040 | (1,084,033 | ) | — | ||||||||||
Other long term liabilities | 2,003 | 9,980 | 1,660 | — | 13,643 | |||||||||||
Total partners’ capital | 1,011,103 | 889,648 | 380,844 | (1,270,492 | ) | 1,011,103 | ||||||||||
Total liabilities and partners’ capital | $ | 2,145,270 | $ | 2,112,451 | $ | 1,346,018 | $ | (2,417,455 | ) | $ | 3,186,284 | |||||
| Year Ended December 31, 2005 | |||||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | |||||||||||||||
| (in thousands) | |||||||||||||||||||
Operating revenues | $ | — | $ | 439,944 | $ | 8,168,657 | $ | (3,567 | ) | $ | 8,605,034 | ||||||||
Costs and expenses | — | 285,072 | 8,104,164 | (3,567 | ) | 8,385,669 | |||||||||||||
Gains on sales of assets | — | (551 | ) | (117 | ) | — | (668 | ) | |||||||||||
Operating income | — | 155,423 | 64,610 | — | 220,033 | ||||||||||||||
Interest expense—net | — | (54,011 | ) | (27,850 | ) | — | (81,861 | ) | |||||||||||
Equity earnings | 162,551 | 57,088 | 23,078 | (222,623 | ) | 20,094 | |||||||||||||
Other income—net | — | 901 | 234 | — | 1,135 | ||||||||||||||
Income from continuing operations | 162,551 | 159,401 | 60,072 | (222,623 | ) | 159,401 | |||||||||||||
Discontinued operations | — | 3,150 | — | — | 3,150 | ||||||||||||||
Net income | $ | 162,551 | $ | 162,551 | $ | 60,072 | $ | (222,623 | ) | $ | 162,551 | ||||||||
F-54
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
| Year Ended December 31, 2004 (as restated) | |||||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | |||||||||||||||
| (in thousands) | |||||||||||||||||||
Operating revenues | $ | — | $ | 420,060 | $ | 5,531,237 | $ | (3,207 | ) | $ | 5,948,090 | ||||||||
Costs and expenses | — | 294,155 | 5,473,751 | (3,207 | ) | 5,764,699 | |||||||||||||
Gains on sales of assets | — | (526 | ) | (527 | ) | — | (1,053 | ) | |||||||||||
Operating income | — | 126,431 | 58,013 | — | 184,444 | ||||||||||||||
Interest expense—net | — | (48,902 | ) | (23,151 | ) | — | (72,053 | ) | |||||||||||
Equity earnings | 138,548 | 57,454 | 28,692 | (202,546 | ) | 22,148 | |||||||||||||
Other income—net | — | 876 | 444 | — | 1,320 | ||||||||||||||
Income from continuing operations | 138,548 | 135,859 | 63,998 | (202,546 | ) | 135,859 | |||||||||||||
Discontinued operations | — | 2,689 | — | — | 2,689 | ||||||||||||||
Net income | $ | 138,548 | $ | 138,548 | $ | 63,998 | $ | (202,546 | ) | $ | 138,548 | ||||||||
| Year Ended December 31, 2003 (as restated) | |||||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | |||||||||||||||
| (in thousands) | |||||||||||||||||||
Operating revenues | $ | — | $ | 399,504 | $ | 3,858,243 | $ | (1,915 | ) | $ | 4,255,832 | ||||||||
Costs and expenses | — | 262,971 | 3,806,316 | (1,915 | ) | 4,067,372 | |||||||||||||
Gain on sale of assets | — | — | (3,948 | ) | — | (3,948 | ) | ||||||||||||
Operating income | — | 136,533 | 55,875 | — | 192,408 | ||||||||||||||
Interest expense—net | — | (52,903 | ) | (31,420 | ) | 73 | (84,250 | ) | |||||||||||
Equity earnings | 121,780 | 37,689 | 20,258 | (166,853 | ) | 12,874 | |||||||||||||
Other income—net | — | 461 | 360 | (73 | ) | 748 | |||||||||||||
Net income | $ | 121,780 | $ | 121,780 | $ | 45,073 | $ | (166,853 | ) | $ | 121,780 | ||||||||
F-55
Table of Contents
Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
| Year Ended December 31, 2005 | ||||||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | ||||||||||||||||
| (in thousands) | ||||||||||||||||||||
Cash flows from continuing operating activities | ||||||||||||||||||||
Net income | $ | 162,551 | $ | 162,551 | $ | 60,072 | $ | (222,623 | ) | $ | 162,551 | |||||||||
Adjustments to reconcile net income to net cash provided by continuing operating activities: | ||||||||||||||||||||
Income from discontinued operations | — | (3,150 | ) | — | — | (3,150 | ) | |||||||||||||
Depreciation and amortization | — | 82,536 | 28,193 | — | 110,729 | |||||||||||||||
Earnings in equity investments, net of distributions | 88,550 | 14,598 | 1,576 | (87,733 | ) | 16,991 | ||||||||||||||
Gains on sales of assets | — | (551 | ) | (117 | ) | — | (668 | ) | ||||||||||||
Changes in assets and liabilities and other | (54,540 | ) | (57,645 | ) | 22,884 | 53,571 | (35,730 | ) | ||||||||||||
Net cash provided by continuing operating activities | 196,561 | 198,339 | 112,608 | (256,785 | ) | 250,723 | ||||||||||||||
Cash flows from discontinued operations | — | 3,782 | — | — | 3,782 | |||||||||||||||
Net cash provided by operating activities | 196,561 | 202,121 | 112,608 | (256,785 | ) | 254,505 | ||||||||||||||
Cash flows from investing activities | (278,806 | ) | (31,529 | ) | (180,486 | ) | 139,906 | (350,915 | ) | |||||||||||
Cash flows from financing activities | 80,107 | (184,126 | ) | 65,097 | 119,029 | 80,107 | ||||||||||||||
Net increase in cash and cash equivalents | (2,138 | ) | (13,534 | ) | (2,781 | ) | 2,150 | (16,303 | ) | |||||||||||
Cash and cash equivalents at beginning of period | 4,116 | 13,596 | 2,826 | (4,116 | ) | 16,422 | ||||||||||||||
Cash and cash equivalents at end of period | $ | 1,978 | $ | 62 | $ | 45 | $ | (1,966 | ) | $ | 119 | |||||||||
F-56
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
| Year Ended December 31, 2004 (as restated) | ||||||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | ||||||||||||||||
| (in thousands) | ||||||||||||||||||||
Cash flows from continuing operating activities | ||||||||||||||||||||
Net income | $ | 138,548 | $ | 138,548 | $ | 63,998 | $ | (202,546 | ) | $ | 138,548 | |||||||||
Adjustments to reconcile net income to net cash provided by continuing operating activities: | ||||||||||||||||||||
Income from discontinued operations | — | (2,689 | ) | — | — | (2,689 | ) | |||||||||||||
Depreciation and amortization | — | 89,438 | 22,846 | — | 112,284 | |||||||||||||||
Earnings in equity investments, net of distributions | 94,509 | (130 | ) | 8,208 | (77,522 | ) | 25,065 | |||||||||||||
Gains on sales of assets | — | (526 | ) | (527 | ) | — | (1,053 | ) | ||||||||||||
Changes in assets and liabilities and other | (158,726 | ) | 29,707 | (30,930 | ) | 151,690 | (8,259 | ) | ||||||||||||
Net cash provided by continuing operating activities | 74,331 | 254,348 | 63,595 | (128,378 | ) | 263,896 | ||||||||||||||
Cash flows from discontinued operations | — | 3,271 | — | — | 3,271 | |||||||||||||||
Net cash provided by operating activities | 74,331 | 257,619 | 63,595 | (128,378 | ) | 267,167 | ||||||||||||||
Cash flows from continuing investing activities | 98 | (26,662 | ) | (40,864 | ) | (115,331 | ) | (182,759 | ) | |||||||||||
Cash flows from discontinued investing activities | — | (7,398 | ) | — | — | (7,398 | ) | |||||||||||||
Cash flows from investing activities | 98 | (34,060 | ) | (40,864 | ) | (115,331 | ) | (190,157 | ) | |||||||||||
Cash flows from financing activities | (90,057 | ) | (229,206 | ) | (25,575 | ) | 254,781 | (90,057 | ) | |||||||||||
Net decrease in cash and cash equivalents | (15,628 | ) | (5,647 | ) | (2,844 | ) | 11,072 | (13,047 | ) | |||||||||||
Cash and cash equivalents at beginning of period | 19,744 | 19,243 | 5,670 | (15,188 | ) | 29,469 | ||||||||||||||
Cash and cash equivalents at end of period | $ | 4,116 | $ | 13,596 | $ | 2,826 | $ | (4,116 | ) | $ | 16,422 | |||||||||
F-57
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
| Year Ended December 31, 2003 (as restated) | ||||||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | ||||||||||||||||
| (in thousands) | ||||||||||||||||||||
Cash flows from operating activities | ||||||||||||||||||||
Net income | $ | 121,780 | $ | 121,780 | $ | 45,073 | $ | (166,853 | ) | $ | 121,780 | |||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||||||
Depreciation and amortization | — | 80,114 | 20,614 | — | 100,728 | |||||||||||||||
Earnings in equity investments, net of distributions | 80,718 | 7,548 | 2,482 | (75,619 | ) | 15,129 | ||||||||||||||
Gain on sale of assets | — | — | (3,948 | ) | — | (3,948 | ) | |||||||||||||
Changes in assets and liabilities and other | 48,432 | 5,576 | 1,075 | (46,348 | ) | 8,735 | ||||||||||||||
Net cash provided by operating activities | 250,930 | 215,018 | 65,296 | (288,820 | ) | 242,424 | ||||||||||||||
Cash flows from continuing investing activities | (175,568 | ) | (164,872 | ) | (37,589 | ) | 203,531 | (174,498 | ) | |||||||||||
Cash flows from investing activities | — | (13,810 | ) | — | — | (13,810 | ) | |||||||||||||
Cash flows from discontinued investing activities | (175,568 | ) | (178,682 | ) | (37,589 | ) | 203,531 | (188,308 | ) | |||||||||||
Cash flows from financing activities | (55,618 | ) | (25,340 | ) | (44,758 | ) | 70,101 | (55,615 | ) | |||||||||||
Net increase (decrease) in cash and cash equivalents | 19,744 | 10,996 | (17,051 | ) | (15,188 | ) | (1,499 | ) | ||||||||||||
Cash and cash equivalents at beginning of period | — | 8,247 | 22,721 | — | 30,968 | |||||||||||||||
Cash and cash equivalents at end of period | $ | 19,744 | $ | 19,243 | $ | 5,670 | $ | (15,188 | ) | $ | 29,469 | |||||||||
NOTE 20. RESTATEMENT OF CONSOLIDATED FINANCIAL STATEMENTS
We are restating our previously reported consolidated financial statements for the fiscal years ended December 31, 2003 and 2004. For the impact of the restated consolidated financial results for the quarterly periods during the years ended December 31, 2005 and 2004, see Note 21. We have determined that our method of accounting for the $33.4 million excess investment in Centennial, previously described as an intangible asset with an indefinite life, and the $27.1 million excess investment in Seaway, previously described as equity method goodwill, was incorrect. Through our accounting for these excess investments in Centennial and Seaway as intangible assets with indefinite lives and equity method goodwill, respectively, we have been testing the amounts for impairment on an annual basis as opposed to amortizing them over a determinable life. We determined that it would be more appropriate to account for these excess investments as intangible assets with determinable lives. As a result, we made non-cash adjustments that reduced the net value of the excess investments in Centennial and Seaway, and increased amortization expense allocated to our equity earnings. The effect of this restatement caused a $3.8 million and $4.0 million reduction to net income as previously reported
F-58
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Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
for the fiscal years ended December 31, 2004 and 2003, respectively. As a result of the accounting correction, net income for the fiscal year ended December 31, 2005, includes a charge of $4.8 million, of which $3.8 million relates to the first nine months. Additionally, partners’ capital at December 31, 2002, reflects a $2.5 million reduction representing the cumulative effect of this correction for fiscal years ended December 31, 2000 through 2002.
While we believe the impacts of these non-cash adjustments are not material to any previously issued financial statements, we determined that the cumulative adjustment for these non-cash items was too material to record in the fourth quarter of 2005, and therefore it was most appropriate to restate prior periods’ results. These non-cash adjustments had no effect on our operating income, compensation expense, debt balances or ability to meet all requirements related to our debt facilities. The restatement had no impact on total cash flows from operating activities, investing activities or financing activities. All amounts in the accompanying consolidated financial statements have been adjusted for this restatement.
We will continue to amortize the $30.0 million excess investment in Centennial related to a contract using units-of-production methodology over a 10-year life. The remaining $3.4 million related to a pipeline will continue to be amortized on a straight-line basis over 35 years. We will continue to amortize the $27.1 million excess investment in Seaway on a straight-line basis over a 39-year life related primarily to a pipeline.
The following tables summarize the impact of the restatement adjustment on previously reported balance sheet amounts for the year ended December 31, 2004, and income statement amounts and cash flow amounts for the years ended December 31, 2004 and 2003 (in thousands):
Balance Sheet Amounts;
| December 31, 2004 | ||||||||||||
| As Previously Reported | Adjustment | As Restated | ||||||||||
Equity investments | $ | 373,652 | $ | (10,345 | ) | $ | 363,307 | |||||
Total assets | $ | 3,196,629 | $ | (10,345 | ) | $ | 3,186,284 | |||||
Capital: | ||||||||||||
General partner’s interest | $ | (33,006 | ) | $ | (2,875 | ) | $ | (35,881 | ) | |||
Limited partners’ interest | 1,054,454 | (7,470 | ) | 1,046,984 | ||||||||
Total partners’ capital | 1,021,448 | (10,345 | ) | 1,011,103 | ||||||||
Total liabilities and partners’ capital | $ | 3,196,629 | $ | (10,345 | ) | $ | 3,186,284 | |||||
F-59
Table of Contents
Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
Income Statement Amounts:
| Years Ended December 31, | ||||||||
| 2004 | 2003 | |||||||
Equity earnings as previously reported | $ | 25,981 | $ | 16,863 | ||||
Adjustment for amortization of excess investments | (3,833 | ) | (3,989 | ) | ||||
Equity earnings as restated | $ | 22,148 | $ | 12,874 | ||||
Net income as previously reported | $ | 142,381 | $ | 125,769 | ||||
Adjustment for amortization of excess investments | (3,833 | ) | (3,989 | ) | ||||
Net income as restated | $ | 138,548 | $ | 121,780 | ||||
Net Income Allocation as previously reported: | ||||||||
Limited Partner Unitholders | $ | 101,307 | $ | 89,191 | ||||
Class B Unitholder | — | 1,806 | ||||||
General Partner | 41,074 | 34,772 | ||||||
Total net income allocated | $ | 142,381 | $ | 125,769 | ||||
Basic and diluted net income per Limited Partner and Class B Unit as previously reported | $ | 1.61 | $ | 1.52 | ||||
Net Income Allocation as restated: | ||||||||
Limited Partner Unitholders | $ | 98,580 | $ | 86,357 | ||||
Class B Unitholder | — | 1,754 | ||||||
General Partner | 39,968 | 33,669 | ||||||
Total net income allocated as restated | $ | 138,548 | $ | 121,780 | ||||
Basic and diluted net income per Limited Partner and Class B Unit as restated | $ | 1.56 | $ | 1.47 | ||||
Cash Flow Amounts;
| Year Ended December 31, 2004 | ||||||||||
| As Previously Reported | Adjustment | As Restated | ||||||||
Cash flows from operating activities: | ||||||||||
Net income | $ | 142,381 | $ | (3,833 | ) | $ | 138,548 | |||
Earnings in equity investments, net of distributions | 21,232 | 3,833 | 25,065 | |||||||
| Year Ended December 31, 2003 | ||||||||||
| As Previously Reported | Adjustment | As Restated | ||||||||
Cash flows from operating activities: | ||||||||||
Net income | $ | 125,769 | $ | (3,989 | ) | $ | 121,780 | |||
Earnings in equity investments, net of distributions | 11,140 | 3,989 | 15,129 | |||||||
F-60
Table of Contents
Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
Partners’ Capital Amounts:
| Outstanding Limited Partner Units | General Partner’s Interest | Limited Partners’ Interests | Accumulated Other Comprehensive Loss | Total | ||||||||||||||
2002: | ||||||||||||||||||
Partners’ capital at December 31, 2002 as previously reported | 53,809,597 | $ | 12,770 | $ | 899,127 | $ | (20,055 | ) | $ | 891,842 | ||||||||
Restatement adjustment | — | (666 | ) | (1,727 | ) | — | (2,393 | ) | ||||||||||
Partners’ capital at December 31, 2002 as restated (unaudited) | 53,809,597 | $ | 12,104 | $ | 897,400 | $ | (20,055 | ) | $ | 889,449 | ||||||||
2003: | ||||||||||||||||||
Partners’ capital at December 31, 2003 as previously reported | 62,998,554 | $ | (7,181 | ) | $ | 1,119,404 | $ | (2,902 | ) | $ | 1,109,321 | |||||||
Restatement adjustment | — | (1,769 | ) | (4,743 | ) | — | (6,512 | ) | ||||||||||
Partners’ capital at December 31, 2003 as restated | 62,998,554 | $ | (8,950 | ) | $ | 1,114,661 | $ | (2,902 | ) | $ | 1,102,809 | |||||||
2004: | ||||||||||||||||||
Partners’ capital at December 31, 2004 as previously reported | 62,998,554 | $ | (33,006 | ) | $ | 1,054,454 | $ | — | $ | 1,021,448 | ||||||||
Restatement adjustment | — | (2,875 | ) | (7,470 | ) | — | (10,345 | ) | ||||||||||
Partners’ capital at December 31, 2004 as restated | 62,998,554 | $ | (35,881 | ) | $ | 1,046,984 | $ | — | $ | 1,011,103 | ||||||||
F-61
Table of Contents
Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
NOTE 21. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
| (as restated) | (as restated) | (as restated) | (as restated) | ||||||||||||
| (in thousands, except per Unit amounts) | |||||||||||||||
2005:(1) | |||||||||||||||
Operating revenues | $ | 1,523,791 | $ | 2,087,385 | $ | 2,500,127 | $ | 2,493,731 | |||||||
Operating income | 61,232 | 53,817 | 43,378 | 61,606 | |||||||||||
Income from continuing operations: | |||||||||||||||
As previously reported | $ | 47,457 | $ | 41,387 | $ | 30,231 | $ | 44,137 | |||||||
Restatement adjustment | (1,152 | ) | (1,311 | ) | (1,348 | ) | — | ||||||||
As restated | $ | 46,305 | $ | 40,076 | $ | 28,883 | $ | 44,137 | |||||||
Income from discontinued operations | $ | 1,124 | $ | 846 | $ | 692 | $ | 488 | |||||||
Net income: | |||||||||||||||
As previously reported | $ | 48,581 | $ | 42,233 | $ | 30,923 | $ | 44,625 | |||||||
Restatement adjustment | (1,152 | ) | (1,311 | ) | (1,348 | ) | — | ||||||||
As restated | $ | 47,429 | $ | 40,922 | $ | 29,575 | $ | 44,625 | |||||||
Basic and diluted net income per Limited Partner Unit from continuing operations:(2)(3) | |||||||||||||||
As previously reported | $ | 0.54 | $ | 0.44 | $ | 0.30 | $ | 0.45 | |||||||
Restatement adjustment | (0.01 | ) | (0.02 | ) | (0.01 | ) | — | ||||||||
As restated | $ | 0.53 | $ | 0.42 | $ | 0.29 | $ | 0.45 | |||||||
Basic and diluted net income per Limited Partner Unit from discontinued operations(3) | $ | 0.01 | $ | 0.01 | $ | 0.01 | $ | — | |||||||
Basic and diluted net income per Limited Partner Unit:(2)(3) | |||||||||||||||
As previously reported | $ | 0.55 | $ | 0.45 | $ | 0.31 | $ | 0.45 | |||||||
Restatement adjustment | (0.01 | ) | (0.02 | ) | (0.01 | ) | — | ||||||||
As restated | $ | 0.54 | $ | 0.43 | $ | 0.30 | $ | 0.45 | |||||||
F-62
Table of Contents
Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
| (as restated) | (as restated) | (as restated) | (as restated) | |||||||||||||
| (in thousands, except per Unit amounts) | ||||||||||||||||
2004:(1) | ||||||||||||||||
Operating revenues | $ | 1,315,942 | $ | 1,352,107 | $ | 1,487,556 | $ | 1,792,485 | ||||||||
Operating income | 53,457 | 41,990 | 36,361 | 52,636 | ||||||||||||
Income from continuing operations: | ||||||||||||||||
As previously reported | $ | 39,989 | $ | 37,348 | $ | 25,135 | $ | 37,220 | ||||||||
Restatement adjustment | (713 | ) | (1,129 | ) | (1,085 | ) | (906 | ) | ||||||||
As restated | $ | 39,276 | $ | 36,219 | $ | 24,050 | $ | 36,314 | ||||||||
Income from discontinued operations | $ | 444 | $ | 411 | $ | 720 | $ | 1,114 | ||||||||
Net income: | ||||||||||||||||
As previously reported | $ | 40,433 | $ | 37,759 | $ | 25,855 | $ | 38,334 | ||||||||
Restatement adjustment | (713 | ) | (1,129 | ) | (1,085 | ) | (906 | ) | ||||||||
As restated | $ | 39,720 | $ | 36,630 | $ | 24,770 | $ | 37,428 | ||||||||
Basic and diluted net income per Limited Partner Unit from continuing operations: | ||||||||||||||||
As previously reported | $ | 0.45 | $ | 0.43 | $ | 0.28 | $ | 0.42 | ||||||||
Restatement adjustment | (0.01 | ) | (0.02 | ) | (0.01 | ) | (0.01 | ) | ||||||||
As restated | $ | 0.44 | $ | 0.41 | $ | 0.27 | $ | 0.41 | ||||||||
Basic and diluted net income per Limited Partner Unit from discontinued operations | $ | 0.01 | $ | — | $ | 0.01 | $ | 0.01 | ||||||||
Basic and diluted net income per Limited Partner Unit: | ||||||||||||||||
As previously reported | $ | 0.46 | $ | 0.43 | $ | 0.29 | $ | 0.43 | ||||||||
Restatement adjustment | (0.01 | ) | (0.02 | ) | (0.01 | ) | (0.01 | ) | ||||||||
As restated | $ | 0.45 | $ | 0.41 | $ | 0.28 | $ | 0.42 | ||||||||
| (1) | The quarterly financial information for 2004 and the first three quarters of 2005 reflect the impact of the restatement. |
| (2) | The sum of the four quarters does not equal the total year due to rounding. |
| (3) | Per Unit calculation includes 6,965,000 Units issued in May and June 2005. |
NOTE 22. SUBSEQUENT EVENTS
In January 2006, we entered into interest rate swaps with a total notional amount of $200.0 million, whereby we will receive a floating rate of interest and will pay a fixed rate of interest for a two-year term. These interest rate swaps were executed to decrease the exposure to potential increases in floating interest rates. Using the balances of outstanding debt at December 31, 2005, these interest rate swaps decrease the level of floating interest rate debt from 41% to 29% of total outstanding debt.
On February 13, 2006, we and an affiliate of Enterprise entered into a letter agreement related to an additional expansion (the “Jonah Expansion”) of the Jonah system (the “Letter Agreement”). The Jonah Expansion will consist of the installation of approximately 90,000 horsepower of gas turbine compression at a new compression station, related new piping and certain related facilities, which is expected to increase capacity of the Jonah system from 1.5 billion cubic feet per day to 2.0 billion cubic feet per day. We expect to enter into a
F-63
Table of Contents
Index to Financial Statements
TEPPCO PARTNERS, L.P.
Notes to Consolidated Financial Statements — Continued
joint venture (“Joint Venture”) agreement with Enterprise relating to the construction and financing of the Jonah Expansion. Enterprise will be responsible for all activities relating to the construction of the Jonah Expansion and will advance all amounts necessary to plan, engineer, construct or complete the Jonah Expansion (anticipated to be approximately $200.0 million). Such advance will constitute a subscription for an equity interest in the proposed Joint Venture (the “Subscription”). We expect the Jonah Expansion to be put into service in late 2006. We have the option to return to Enterprise up to 100% of the amount of the Subscription. If we return a portion of the Subscription to Enterprise, our relative interests in the proposed Joint Venture will be adjusted accordingly. The proposed Joint Venture will terminate without liability to either party if we return 100% of the Subscription.
F-64
Table of Contents
Index to Financial Statements
INDEPENDENT AUDITORS’ REPORT
To the Board of Directors and Members of
DCP Midstream, LLC
Denver, Colorado
We have audited the accompanying consolidated balance sheets of DCP Midstream, LLC and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations and comprehensive income, members’ equity, and cash flows for the years then ended. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, 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 DCP Midstream, LLC and subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for the years then ended 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.
/s/ DELOITTE & TOUCHE LLP |
| Denver, Colorado |
| March 14, 2007 |
Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
CONSOLIDATED BALANCE SHEETS
As of December 31, 2006 and 2005
(millions)
| 2006 | 2005 | |||||||
| ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 68 | $ | 59 | ||||
Short-term investments | 437 | 627 | ||||||
Accounts receivable: | ||||||||
Customers, net of allowance for doubtful accounts of $3 million and $4 million, respectively | 933 | 1,237 | ||||||
Affiliates | 283 | 340 | ||||||
Other | 56 | 59 | ||||||
Inventories | 87 | 110 | ||||||
Unrealized gains on mark-to-market and hedging instruments | 242 | 252 | ||||||
Other | 23 | 22 | ||||||
Total current assets | 2,129 | 2,706 | ||||||
Property, plant and equipment, net | 3,869 | 3,836 | ||||||
Restricted investments | 102 | 364 | ||||||
Investments in unconsolidated affiliates | 204 | 169 | ||||||
Intangible assets: | ||||||||
Commodity sales and purchases contracts, net | 58 | 66 | ||||||
Goodwill | 421 | 421 | ||||||
Total intangible assets | 479 | 487 | ||||||
Unrealized gains on mark-to-market and hedging instruments | 29 | 60 | ||||||
Deferred income taxes | 4 | 3 | ||||||
Other non-current assets | 33 | 86 | ||||||
Other non-current assets—affiliates | 47 | — | ||||||
Total assets | $ | 6,896 | $ | 7,711 | ||||
| LIABILITIES AND MEMBERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable: | ||||||||
Trade | $ | 1,490 | $ | 2,035 | ||||
Affiliates | 92 | 42 | ||||||
Other | 42 | 42 | ||||||
Current maturities of long-term debt | — | 300 | ||||||
Unrealized losses on mark-to-market and hedging instruments | 216 | 244 | ||||||
Distributions payable to members | 127 | 185 | ||||||
Accrued interest payable | 47 | 45 | ||||||
Accrued taxes | 27 | 46 | ||||||
Other | 136 | 129 | ||||||
Total current liabilities | 2,177 | 3,068 | ||||||
Deferred income taxes | 17 | — | ||||||
Long-term debt | 2,115 | 1,760 | ||||||
Unrealized losses on mark-to-market and hedging instruments | 33 | 54 | ||||||
Other long-term liabilities | 226 | 224 | ||||||
Non-controlling interests | 71 | 95 | ||||||
Commitments and contingent liabilities | ||||||||
Members’ equity: | ||||||||
Members’ interest | 2,107 | 2,107 | ||||||
Retained earnings | 153 | 411 | ||||||
Accumulated other comprehensive loss | (3 | ) | (8 | ) | ||||
Total members’ equity | 2,257 | 2,510 | ||||||
Total liabilities and members’ equity | $ | 6,896 | $ | 7,711 | ||||
See Notes to Consolidated Financial Statements.
F-66
Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
Years Ended December 31, 2006 and 2005
(millions)
| 2006 | 2005 | |||||||
Operating revenues: | ||||||||
Sales of natural gas and petroleum products | $ | 9,137 | $ | 10,011 | ||||
Sales of natural gas and petroleum products to affiliates | 2,813 | 2,785 | ||||||
Transportation, storage and processing | 308 | 253 | ||||||
Trading and marketing gains (losses) | 77 | (15 | ) | |||||
Total operating revenues | 12,335 | 13,034 | ||||||
Operating costs and expenses: | ||||||||
Purchases of natural gas and petroleum products | 9,322 | 10,133 | ||||||
Purchases of natural gas and petroleum products from affiliates | 789 | 830 | ||||||
Operating and maintenance | 462 | 447 | ||||||
Depreciation and amortization | 284 | 287 | ||||||
General and administrative | 234 | 195 | ||||||
Gain on sale of assets | (28 | ) | (2 | ) | ||||
Total operating costs and expenses | 11,063 | 11,890 | ||||||
Operating income | 1,272 | 1,144 | ||||||
Gain on sale of general partner interest in TEPPCO | — | 1,137 | ||||||
Equity in earnings of unconsolidated affiliates | 20 | 22 | ||||||
Non-controlling interest in (income) loss | (15 | ) | 1 | |||||
Interest income | 26 | 26 | ||||||
Interest expense | (145 | ) | (154 | ) | ||||
Income from continuing operations before income taxes | 1,158 | 2,176 | ||||||
Income tax expense | (23 | ) | (9 | ) | ||||
Income from continuing operations | 1,135 | 2,167 | ||||||
Income from discontinued operations, net of income taxes | — | 3 | ||||||
Net income | 1,135 | 2,170 | ||||||
Other comprehensive income (loss): | ||||||||
Foreign currency translation adjustment | — | (8 | ) | |||||
Canadian business distributed to Duke Energy | — | (70 | ) | |||||
Net unrealized gains on cash flow hedges | 5 | — | ||||||
Reclassification of cash flow hedges into earnings | — | 1 | ||||||
Total other comprehensive income (loss) | 5 | (77 | ) | |||||
Total comprehensive income | $ | 1,140 | $ | 2,093 | ||||
See Notes to Consolidated Financial Statements.
F-67
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 2006 and 2005
(millions)
| 2006 | 2005 | |||||||
Cash flows from operating activities: | ||||||||
Net income | $ | 1,135 | $ | 2,170 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Income from discontinued operations | — | (3 | ) | |||||
Gain from sale of equity investment in TEPPCO | — | (1,137 | ) | |||||
Gain on sale of assets | (28 | ) | (2 | ) | ||||
Depreciation and amortization | 284 | 287 | ||||||
Equity in earnings of unconsolidated affiliates, net of distributions | — | 15 | ||||||
Deferred income tax expense (benefit) | 17 | (2 | ) | |||||
Non-controlling interest in income (loss) | 15 | (1 | ) | |||||
Other, net | (3 | ) | 2 | |||||
Changes in operating assets and liabilities which provided (used) cash: | ||||||||
Accounts receivable | 314 | (432 | ) | |||||
Inventories | 23 | (37 | ) | |||||
Net unrealized (gains) losses on mark-to-market and hedging instruments | (1 | ) | 9 | |||||
Accounts payable | (495 | ) | 910 | |||||
Accrued interest payable | 1 | (14 | ) | |||||
Other | (16 | ) | (12 | ) | ||||
Net cash provided by continuing operations | 1,246 | 1,753 | ||||||
Net cash provided by discontinued operations | — | 11 | ||||||
Net cash provided by operating activities | 1,246 | 1,764 | ||||||
Cash flows from investing activities: | ||||||||
Capital and acquisition expenditures | (325 | ) | (212 | ) | ||||
Investments in unconsolidated affiliates | (44 | ) | (24 | ) | ||||
Distributions received from unconsolidated affiliates | 2 | — | ||||||
Purchases of available-for-sale securities | (19,666 | ) | (17,986 | ) | ||||
Proceeds from sales of available-for-sale securities | 20,121 | 17,260 | ||||||
Proceeds from sales of assets | 81 | 53 | ||||||
Proceeds from sale of general partner interest in TEPPCO | — | 1,100 | ||||||
Other | — | 9 | ||||||
Net cash provided by continuing operations | 169 | 200 | ||||||
Net cash used in discontinued operations | — | (13 | ) | |||||
Net cash provided by investing activities | 169 | 187 | ||||||
Cash flows from financing activities: | ||||||||
Payment of dividends and distributions to members | (1,451 | ) | (2,313 | ) | ||||
Proceeds from issuance of equity securities of a subsidiary, net of offering costs | — | 206 | ||||||
Contribution received from ConocoPhillips | — | 398 | ||||||
Payment of debt | (320 | ) | (607 | ) | ||||
Proceeds from issuing debt | 378 | 408 | ||||||
Loans made to Duke Capital LLC and ConocoPhillips | — | (1,100 | ) | |||||
Repayment of loans by Duke Capital LLC and ConocoPhillips | — | 1,100 | ||||||
Net cash (paid to) received from non-controlling interests | (10 | ) | 3 | |||||
Other | (3 | ) | (2 | ) | ||||
Net cash used in continuing operations | (1,406 | ) | (1,907 | ) | ||||
Net cash used in discontinued operations | — | (44 | ) | |||||
Net cash used in financing activities | (1,406 | ) | (1,951 | ) | ||||
Net increase in cash and cash equivalents | 9 | — | ||||||
Cash and cash equivalents, beginning of year | 59 | 59 | ||||||
Cash and cash equivalents, end of year | $ | 68 | $ | 59 | ||||
Supplementary cash flow information: | ||||||||
Cash paid for interest (net of amounts capitalized) | $ | 141 | $ | 163 | ||||
See Notes to Consolidated Financial Statements.
F-68
Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
Years Ended December 31, 2006 and 2005
(millions)
Members’ Interest | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total | ||||||||||||
Balance, January 1, 2005 | $ | 1,709 | $ | 909 | $ | 69 | $ | 2,687 | |||||||
Dividends and distributions | — | (2,414 | ) | — | (2,414 | ) | |||||||||
Distribution of Canadian business | — | (254 | ) | (70 | ) | (324 | ) | ||||||||
Contributions | 398 | — | — | 398 | |||||||||||
Net income | — | 2,170 | — | 2,170 | |||||||||||
Foreign currency translation adjustment | — | — | (8 | ) | (8 | ) | |||||||||
Reclassification of cash flow hedges into earnings | — | — | 1 | 1 | |||||||||||
Balance, December 31, 2005 | 2,107 | 411 | (8 | ) | 2,510 | ||||||||||
Dividends and distributions | — | (1,393 | ) | — | (1,393 | ) | |||||||||
Net income | — | 1,135 | — | 1,135 | |||||||||||
Net unrealized gains on cash flow hedges | — | — | 5 | 5 | |||||||||||
Balance, December 31, 2006 | $ | 2,107 | $ | 153 | $ | (3 | ) | $ | 2,257 | ||||||
See Notes to Consolidated Financial Statements.
F-69
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements
Years Ended December 31, 2006 and 2005
1. General and Summary of Significant Accounting Policies
Basis of Presentation—DCP Midstream, LLC, formerly Duke Energy Field Services, LLC, with its consolidated subsidiaries, us, we, our, or the Company, is a joint venture owned 50% by Duke Energy Corporation, or Duke Energy, and 50% by ConocoPhillips. We operate in the midstream natural gas industry. Our primary operations consist of natural gas gathering, processing, compression, transportation and storage, and natural gas liquid, or NGL, fractionation, transportation, gathering, treating, processing and storage, as well as marketing, from which we generate revenues primarily by trading and marketing natural gas and NGLs. The Second Amended and Restated LLC Agreement dated July 5, 2005, as amended, or the LLC Agreement, limits the scope of our business to the midstream natural gas industry in the United States and Canada, the marketing of NGLs in Mexico, and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our board of directors.
To support and facilitate our continued growth, we formed DCP Midstream Partners, LP, a master limited partnership, or DCP Partners, of which our subsidiary, DCP Midstream GP, LP, acts as general partner. In September 2005, DCP Partners filed a Registration Statement on Form S-1 with the Securities and Exchange Commission, or SEC, to register the initial public offering of its limited partnership units to the public. The initial public offering closed in December 2005. We own approximately 41% of the limited partnership interests in DCP Partners and a 2% general partnership interest. As the general partner of DCP Partners, we have responsibility for its operations. DCP Partners is accounted for as a consolidated subsidiary.
In July 2005, Duke Energy transferred a 19.7% interest in our Company to ConocoPhillips in exchange for direct and indirect monetary and non-monetary consideration, effectively decreasing Duke Energy’s membership interest in our Company to 50% and increasing ConocoPhillips’ membership interest in our Company to 50%, referred to as “the 50-50 Transaction.” Included in this transaction, we distributed to Duke Energy substantially all of our Canadian business, made a disproportionate cash distribution of approximately $1,100 million to Duke Energy using the proceeds from the sale of our general partner interest in TEPPCO and paid a $245 million proportionate distribution to Duke Energy and ConocoPhillips. In addition, ConocoPhillips contributed cash of $398 million to our Company. Under the terms of the amended and restated LLC Agreement, proceeds from this contribution were designated for the acquisition or improvement of property, plant and equipment. At December 31, 2006, there was no remaining restricted investment balance related to this contribution.
On June 28, 2006, Duke Energy’s board of directors approved a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses, including its 50% ownership interest in us, to Duke Energy shareholders. This transaction occurred on January 2, 2007. As a result of this transaction, we are no longer 50% owned by Duke Energy. Duke Energy’s 50% ownership interest in us was transferred to a new company, Spectra Energy Corp, or Spectra Energy. This transaction is referred to in this report as “the Spectra spin.” For the historical periods included in this report, references to Spectra Energy are interchangeable with Duke Energy. On a prospective basis, Spectra Energy refers to the newly formed public company.
We are governed by a five member board of directors, consisting of two voting members from each parent and our Chief Executive Officer and President, a non-voting member. All decisions requiring board of directors’ approval are made by simple majority vote of the board, but must include at least one vote from both a Spectra Energy (or Duke Energy prior to January 2, 2007) and ConocoPhillips board member. In the event the board cannot reach a majority decision, the decision is appealed to the Chief Executive Officers of both Spectra Energy and ConocoPhillips.
F-70
Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
The consolidated financial statements include the accounts of the Company and all majority-owned subsidiaries where we have the ability to exercise control, variable interest entities where we are the primary beneficiary, and undivided interests in jointly owned assets. We also consolidate DCP Partners, which we control as the general partner and where the limited partners do not have substantive kick-out or participating rights. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. Intercompany balances and transactions have been eliminated.
Use of Estimates—Conformity with accounting principles generally accepted in the United States of America requires management to make 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 of current and expected future events, actual results could be different from those estimates.
Acquisitions—We consolidate assets and liabilities from acquisitions as of the purchase date, and include earnings from acquisitions in consolidated earnings subsequent to the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair values on the date of acquisition. If the acquisition constitutes a business, any excess purchase price over the estimated fair value of the acquired assets and liabilities is recorded as goodwill.
Reclassifications—Certain prior period amounts have been reclassified in the consolidated financial statements to conform to the current period presentation.
Cash and Cash Equivalents—Cash and cash equivalents includes all cash balances and highly liquid investments with an original maturity of three months or less.
Short-Term and Restricted Investments—We invest available cash balances in various financial instruments, such as tax-exempt debt securities, that have stated maturities of 20 years or more. These instruments provide for a high degree of liquidity through features, which allow for the redemption of the investment at its face amount plus earned income. As we generally intend to sell these instruments within one year or less from the balance sheet date, and as they are available for use in current operations, they are classified as current assets, unless otherwise restricted. We have classified all short-term and restricted debt investments as available-for-sale under Statement of Financial Accounting Standards, or SFAS, No. 115,“Accounting for Certain Investments in Debt and Equity Securities,” and they are carried at fair market value. Unrealized gains and losses on available-for-sale securities are recorded in the consolidated balance sheets as accumulated other comprehensive income (loss), or AOCI. No such gains or losses were deferred in AOCI at December 31, 2006 or 2005. The cost, including accrued interest on investments, approximates fair value, due to the short-term, highly liquid nature of the securities held by us and as interest rates are re-set on a daily, weekly or monthly basis.
Inventories—Inventories consist primarily of natural gas and NGLs held in storage for transportation and processing and sales commitments. Inventories are valued at the lower of weighted average cost or market. Transportation costs are included in inventory on the consolidated balance sheets.
Accounting for Risk Management and Hedging Activities and Financial Instruments—Each derivative not qualifying for the normal purchases and normal sales exception under SFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities,”or SFAS 133, as amended, is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on mark-to-market and
F-71
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
hedging instruments. Derivative assets and liabilities remain classified in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments at fair value until the contractual delivery period impacts earnings.
We designate each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or a normal purchase or normal sale contract, while certain non-trading derivatives, which are related to asset based activity, are non-trading mark-to-market derivatives. For each of our derivatives, the accounting method and presentation in the consolidated statements of operations and comprehensive income are as follows:
Classification of Contract | Accounting Method | Presentation of Gains & Losses or Revenue & | ||
Trading Derivatives | Mark-to-market method(a) | Net basis in trading and marketing gains (losses) | ||
Non-Trading Derivatives: | ||||
Cash Flow Hedge | Hedge method(b) | Gross basis in the same consolidated statements of operations and comprehensive income category as the related hedged item | ||
Fair Value Hedge | Hedge method(b) | Gross basis in the same consolidated statements of operations and comprehensive income category as the related hedged item | ||
Normal Purchase or Normal Sale | Accrual method(c) | Gross basis upon settlement in the corresponding consolidated statements of operations and comprehensive income category based on purchase or sale | ||
Non-Trading Derivatives | Mark-to-market method(a) | Net basis in trading and marketing gains (losses) | ||
| (a) | Mark-to-market—An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations and comprehensive income in trading and marketing gains (losses) during the current period. |
| (b) | Hedge method—An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations and comprehensive income for the effective portion until the service is provided or the associated delivery period impacts earnings. For fair value hedges, the changes in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations and comprehensive income in the same category as the related hedged item. |
| (c) | Accrual method—An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations and comprehensive income for changes in fair value of a contract until the service is provided or the associated delivery period impacts earnings. |
F-72
Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
Cash Flow and Fair Value Hedges—For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge in accordance with SFAS 133. In addition, we formally assess, both at the inception of the hedge and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.
The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as AOCI and the ineffective portion is recorded in the consolidated statements of operations and comprehensive income. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations and comprehensive income in the same accounts as the item being hedged. We discontinue hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not 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 accounting method prospectively. The derivative continues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings.
For derivatives designated as fair value hedges, we recognize the gain or loss on the derivative instrument, as well as the offsetting changes in value of the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the consolidated statements of operations and comprehensive income.
Valuation—When available, quoted market prices or prices obtained through external sources are used to determine 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 pricing models developed primarily from historical and expected correlations with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.
Property, Plant and Equipment—Property, plant and equipment are recorded at original cost. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.
Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and 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. We recognize a liability for conditional asset retirement obligations as soon as the fair value of the liability can be
F-73
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
reasonably estimated. A conditional asset retirement obligation is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity.
Impairment of Unconsolidated Affiliates—We evaluate our unconsolidated affiliates for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investments may have experienced an other than temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether any impairment has occurred. Management assesses the fair value of our unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss.
Intangible Assets—Intangible assets consist of goodwill, and commodity sales and purchases contracts. Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. Commodity sales and purchases contracts are amortized on a straight-line basis over the term of the contract, ranging from one to 25 years.
We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Impairment testing of goodwill consists of a two-step process. The first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves comparing the 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 fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.
Impairment of Long-Lived Assets, Assets Held for Sale and Discontinued Operations—We evaluate whether the carrying value of long-lived assets, excluding goodwill, has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to:
| • | A significant adverse change in legal factors or 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; |
| • | A significant adverse 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. |
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but 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 the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.
We use the criteria in SFAS No. 144,“Accounting for the Impairment or Disposal of Long-Lived Assets,”or SFAS 144, to determine when an asset is classified as held for sale. Upon classification as held for sale, the long-lived asset is measured at the lower of its carrying amount or fair value less cost to sell, depreciation is ceased and the asset is separately presented on the consolidated balance sheets.
If an asset held for sale or sold (1) has clearly distinguishable operations and cash flows, generally at the plant level, (2) has direct cash flows of the held for sale or sold component that will be eliminated (from the perspective of the held for sale or sold component), and (3) if we are unable to exert significant influence over the disposed component, then the related results of operations for the current and prior periods, including any related impairments and gains or losses on sales are reflected as income from discontinued operations in the consolidated statements of operations and comprehensive income. If an asset held for sale or sold does not have clearly distinguishable operations and cash flows, impairments and gains or losses on sales are recorded as gain on sale of assets in the consolidated statements of operations and comprehensive income.
Unamortized Debt Premium, Discount and Expense—Premiums, discounts and expenses incurred with the issuance of long-term debt are amortized over the terms of the debt using the effective interest method. These premiums and discounts are recorded on the consolidated balance sheets as an offset to long-term debt. These expenses are recorded on the consolidated balance sheets as other non-current assets.
Distributions—Under the terms of the LLC Agreement, we are required to make quarterly distributions to Spectra Energy and ConocoPhillips based on allocated taxable income. The LLC Agreement provides for taxable income to be allocated in accordance with Internal Revenue Code Section 704(c). This Code Section accounts for the variation between the adjusted tax basis and the fair market value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either member with a minimum of each members’ tax, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 50% for both Spectra Energy and ConocoPhillips. Prior to January 2, 2007, the capital accounts were maintained at 50% for both Duke Energy and ConocoPhillips, and prior to July 1, 2005, the capital accounts were maintained at 69.7% for Duke Energy and 30.3% for ConocoPhillips. During the years ended December 31, 2006 and 2005, we paid distributions of $650 million and $389 million, respectively, based on estimated annual taxable income allocated to the members according to their respective ownership percentages at the date the distributions became due.
Our board of directors determines the amount of the quarterly dividend to be paid to Spectra Energy (or Duke Energy prior to January 2, 2007) and ConocoPhillips, by considering net income, cash flow or any other criteria deemed appropriate. During the years ended December 31, 2006 and 2005, we paid total dividends of $801 million and $1,925 million, respectively. The $1,925 million paid during the year ended December 31, 2005, is comprised of a disproportionate cash distribution of approximately $1,100 million to Duke Energy using the proceeds from the sale of our general partner interest in TEPPCO as part of the 50-50 Transaction, a $245 million proportionate distribution to Duke Energy and ConocoPhillips as part of the 50-50 Transaction, and
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Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
$580 million in proportionate distributions to Duke Energy and ConocoPhillips, which were allocated in accordance with our partners’ respective ownership percentages. The $801 million paid during the year ended December 31, 2006, is comprised of proportionate distributions to Duke Energy and ConocoPhillips, which were allocated in accordance with our partners’ respective ownership percentages. The LLC Agreement restricts payment of dividends except with the approval of both members.
DCP Partners considers the payment of a quarterly distribution to the holders of its common units and subordinated units, to the extent DCP Partners has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner, a wholly-owned subsidiary of ours. There is no guarantee, however, that DCP Partners will pay the minimum quarterly distribution on the units in any quarter. DCP Partners will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under its credit agreement. Our 41% limited partner interest in DCP Partners primarily consists of subordinated units. The subordinated units are entitled to receive the minimum quarterly distribution only after DCP Partners’ common unitholders have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. The subordination period will end on December 31, 2010 if certain distribution tests are met and earlier if certain more stringent tests are met. At such time that the subordination period ends, the subordinated units will be converted to common units. During the year ended December 31, 2006, DCP Partners paid distributions of approximately $13 million to its public unitholders. We hold general partner incentive distribution rights, which entitle us to receive an increasing share of available cash when pre-defined distribution targets are achieved.
Foreign Currency Translation—We translated assets and liabilities of our Canadian operations, where the Canadian dollar was the functional currency, at the period-end exchange rates. Revenues and expenses were translated using average monthly exchange rates during the period, which approximates the exchange rates at the time of each transaction during the period. Foreign currency translation adjustments are included in the consolidated statements of comprehensive income. In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. As a result, there were no translation gains or losses in AOCI at December 31, 2006 and 2005.
Revenue Recognition—We generate the majority of our revenues from natural gas gathering, processing, compression, transportation and storage, and natural gas liquid, or NGL, fractionation, transportation, gathering, treating, processing and storage, as well as trading and marketing of natural gas and NGLs.
We obtain access to raw natural gas and provide our midstream natural gas services principally under contracts that contain a combination of one or more of the following arrangements.
| • | Fee-based arrangements—Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, or transporting of natural gas. Our fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase raw natural gas at the wellhead, or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the fees we would otherwise charge for gathering of raw natural gas from the wellhead location to the delivery point. The revenue we earn is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues from these arrangements would be reduced. |
| • | Percent-of-proceeds/index arrangements—Under percentage-of-proceeds/index arrangements, we generally purchase natural gas from producers at the wellhead, gather the wellhead natural gas |
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Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas and NGLs at index prices based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas and the NGLs, regardless of the actual amount of the sales proceeds we receive. Under these types of arrangements, our revenues correlate directly with the price of natural gas and NGLs. |
| • | Keep-whole arrangements—Under the terms of a keep-whole processing contract, we gather raw natural gas from the producer for processing, market the NGLs and return to the producer residue natural gas with a Btu content equivalent to the Btu content of the raw natural gas gathered. This arrangement keeps the producer whole to the thermal value of the raw natural gas received. Under these types of contracts, we are exposed to the “frac spread.” The frac spread is the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL prices are higher relative to natural gas prices. |
Our trading and marketing of natural gas and NGLs, consists of physical purchases and sales, as well as derivative instruments.
We recognize revenue for sales and services under the four revenue recognition criteria, as follows:
Persuasive evidence of an arrangement exists—Our customary practice is to enter into a written contract, executed by both us and the customer.
Delivery—Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.
The fee is fixed or determinable—We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.
Collectability is probable—Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, cash position and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is recognized when the fee is collected.
We generally report revenues gross in the consolidated statements of operations and comprehensive income, as we typically act as the principal in these transactions, take custody of the product, and incur the risks and rewards of ownership. Effective April 1, 2006, any new or amended contracts for certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are reported net as one transaction. We recognize revenues for our NGL and residue gas derivative trading activities net in the consolidated statements of operations and comprehensive income as trading and marketing gains (losses). These activities include mark-to-market gains and losses on energy trading contracts, and the financial or physical settlement of energy trading contracts.
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Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
Revenue for goods and services provided but not invoiced is estimated each month and recorded along with related purchases of goods and services used but not invoiced. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. There are no material differences between the actual amounts and the estimated amounts of revenues and purchases recorded at December 31, 2006 and 2005.
Gas and NGL Imbalance Accounting—Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as other receivables or other payables using current market prices or the weighted average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash. Included in the consolidated balance sheets as accounts receivable—other as of December 31, 2006 and 2005 were imbalances totaling $45 million and $59 million, respectively. Included in the consolidated balance sheets as accounts payable—other, as of December 31, 2006 and 2005 were imbalances totaling $42 million at both periods.
Significant Customers—ConocoPhillips, an affiliated company, was a significant customer in both of the past two years. Sales to ConocoPhillips, including its 50% owned equity method investment, ChevronPhillips Chemical Company LLC, or CP Chem, totaled approximately $2,677 million during 2006 and $2,513 million during 2005.
Environmental Expenditures—Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not generate current or future revenue, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Environmental liabilities as of December 31, 2006 and 2005, included in the consolidated balance sheets, totaled $6 million for both periods recorded as other current liabilities, and totaled $6 million and $7 million, respectively, recorded as other long-term liabilities.
Stock-Based Compensation—Under our 2006 Long Term Incentive Plan, or 2006 Plan, equity instruments may be granted to our key employees. The 2006 Plan provides for the grant of Relative Performance Units, or RPU’s, Strategic Performance Units, or SPU’s, and Phantom Units. Prior to January 2, 2007, each of the above units constitutes a notional unit equal to the weighted average fair value of a common share or unit of ConocoPhillips, Duke Energy and DCP Partners, weighted 45%, 45% and 10%, respectively. Upon the Spectra spin, the 45% weighting attributable to Duke Energy will be valued as one common share of Duke Energy and one-half of one common share of Spectra Energy. The 2006 Plan also provides for the grant of DCP Partners’ Phantom Units, which constitute a notional unit equal to the fair value of DCP Partners’ common units. Each unit provides for the grant of dividend or distribution equivalent rights. The 2006 Plan is administered by the compensation committee of our board of directors. We first granted awards under the 2006 Plan during the second quarter of 2006.
Under DCP Partners’ Long Term Incentive Plan, or DCP Partners’ Plan, equity instruments may be granted to DCP Partners’ key employees. DCP Midstream GP, LLC adopted the DCP Partners’ Plan for employees, consultants and directors of DCP Midstream GP, LLC and its affiliates who perform services for DCP Partners. The DCP Partners’ Plan provides for the grant of unvested units, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of distribution equivalent rights. Subject to adjustment for certain events, an aggregate of 850,000 common units may be delivered pursuant to awards under
F-78
Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
the DCP Partners’ Plan. Awards that are canceled, forfeited or withheld to satisfy DCP Midstream GP, LLC’s tax withholding obligations are available for delivery pursuant to other awards. The DCP Partners’ Plan is administered by the compensation committee of DCP Midstream GP, LLC’s board of directors. DCP Partners first granted awards under this plan during the first quarter of 2006.
Through July 1, 2005, we accounted for stock-based compensation in accordance with the intrinsic value recognition and measurement principles of Accounting Principles Board, or APB, Opinion No. 25, or APB 25,“Accounting for Stock Issued to Employees,” and Financial Accounting Standards Board, or FASB, Interpretation No. 44, or FIN 44,“Accounting for Certain Transactions Involving Stock Compensation—an Interpretation of APB Opinion No. 25.” Under that method, compensation expense was measured as the intrinsic value of an award at the measurement dates. The intrinsic value of an award is the amount by which the quoted market price of the underlying stock exceeds the amount, if any, an employee would be required to pay to acquire the stock. Since the exercise price for all options granted under the plan was equal to the market value of the underlying common stock on the date of grant, no compensation expense has historically been recognized in the accompanying consolidated statements of operations and comprehensive income. Compensation expense for phantom stock awards and other stock awards was recorded from the date of grant over the required vesting period based on the market value of the awards at the date of grant. Compensation expense for stock-based performance awards was recorded over the required vesting period, and adjusted for increases and decreases in market value at each reporting date up to the measurement dates.
Under its 1998 Long-Term Incentive Plan, or 1998 Plan, Duke Energy granted certain of our key employees stock options, phantom stock awards, stock-based performance awards and other stock awards to be settled in shares of Duke Energy’s common stock. Upon execution of the 50-50 Transaction in July 2005, certain of our employees who had been issued awards under the 1998 Plan incurred a change in status from Duke Energy employees to non-employees. As a result, all outstanding stock-based awards were required to be remeasured as of July 2005 under EITF Issue No. 96-18, or EITF 96-18,“Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services,”using the fair value method prescribed in SFAS No. 123,“Accounting for Stock-Based Compensation,” or SFAS 123. Compensation expense is recognized prospectively beginning at the date of the change in status over the remaining vesting period based on the fair value of each award at each reporting date. The fair value of stock options is determined using the Black-Scholes option pricing model and the fair value of all other awards is determined based on the closing equity price at each measurement date.
Effective January 1, 2006, we adopted the provisions of SFAS No. 123(R) (Revised 2004)“Share-Based Payment,”or SFAS 123R, which establishes accounting for stock-based awards exchanged for employee and non-employee services. Accordingly, equity classified stock-based compensation cost is measured at grant date, based on the fair value of the award, and is recognized as expense over the requisite service period. Liability classified stock-based compensation cost is remeasured at each reporting date, and is recognized over the requisite service period.
We elected to adopt the modified prospective application method as provided by SFAS 123R and, accordingly, financial statement amounts for the prior periods presented in these consolidated financial statements have not been restated. Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award.
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Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
We recorded stock-based compensation expense for the years ended December 31, 2006 and 2005 as follows, the components of which are further described in Note 13:
| Year Ended December 31, | ||||||
| 2006 | 2005 | |||||
| (millions) | ||||||
Performance awards | $ | 4 | $ | 3 | ||
Phantom awards | 4 | 2 | ||||
Total | $ | 8 | $ | 5 | ||
The following table shows what net income would have been if the fair value recognition provisions of SFAS 123 had been applied to all stock-based compensation awards for the year ended December 31, 2005.
Year Ended December 31, 2005 | ||||
| (millions) | ||||
Net income, as reported | $ | 2,170 | ||
Add: stock-based compensation expense included in reported net income | 3 | |||
Deduct: total stock-based compensation expense determined under fair value-based method for all awards | (3 | ) | ||
Pro forma net income | $ | 2,170 | ||
Accounting for Sales of Units by a Subsidiary—In December 2005, we formed DCP Partners through the contribution of certain assets and investments in unconsolidated affiliates in exchange for common units, subordinated units and a 2% general partner interest. Concurrent with the formation, we sold approximately 58% of DCP Partners to the public, through an initial public offering, for proceeds of approximately $206 million, net of offering costs. We account for sales of units by a subsidiary under Staff Accounting Bulletin No. 51, or SAB 51,“Accounting for Sales of Stock of a Subsidiary.” Under SAB 51, companies may elect, via an accounting policy decision, to record a gain or loss on the sale of common equity of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the units sold. Under SAB 51, a gain on the sale of subsidiary equity cannot be recognized until multiple classes of outstanding securities convert to common equity. As a result, we have deferred approximately $150 million of gain on sale of common units in DCP Partners as other long-term liabilities in the consolidated balance sheets. We will recognize this gain in earnings upon conversion of all of our subordinated units in DCP Partners to common units.
Income Taxes—We are structured as a limited liability company, which is a pass-through entity for U.S. income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns. The income tax expense related to this corporation is included in our income tax expense, along with state, local, franchise and margin taxes of the limited liability company and other subsidiaries. In addition, until July 1, 2005, we had Canadian subsidiaries that were subject to Canadian income taxes.
We follow the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities.
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Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
New Accounting Standards—SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FAS 115,” or SFAS 159. In February 2007, the FASB issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 159 on our consolidated results of operations, cash flows or financial position.
SFAS No. 157 “Fair Value Measurements,” or SFAS 157. In September 2006, the FASB issued SFAS 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Under SFAS 157, fair value measurements are disclosed by level within that hierarchy. SFAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value to any new circumstances. SFAS 157 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 157 on our consolidated results of operations, cash flows or financial position.
SFAS No. 154 “Accounting Changes and Error Corrections,” or SFAS 154. In June 2005, the FASB issued SFAS 154, a replacement of APB Opinion No. 20, or APB 20,“Accounting Changes” and SFAS No. 3,“Reporting Accounting Changes in Interim Financial Statements.” Among other changes, SFAS 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented under the new accounting principle, unless it is impracticable to do so. SFAS 154 also (1) provides that a change in depreciation or amortization of a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) carries forward without change the guidance within APB 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate. The adoption of SFAS 154 on January 1, 2006, did not have a material impact on our consolidated results of operations, cash flows or financial position.
FIN No. 48 “Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement 109,” or FIN 48. In July 2006, the FASB issued FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN 48 are effective for us on January 1, 2007. The adoption of FIN 48 is not expected to have a material impact on our combined results of operations, cash flows or financial position.
EITF Issue No. 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” or EITF 04-13. In September 2005, the FASB ratified the EITF’s consensus on Issue 04-13, which requires an entity to treat sales and purchases of inventory between the entity and the same counterparty as one transaction for purposes of applying APB Opinion No. 29 when such transactions are entered into in contemplation of each other. When such transactions are legally contingent on each other, they are considered to have been entered into in contemplation of each other. The EITF also agreed on other factors that should be considered in determining
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Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
whether transactions have been entered into in contemplation of each other. EITF 04-13 was applied to new arrangements that we entered into after March 31, 2006. The adoption of EITF 04-13 did not have a material impact on our consolidated results of operations, cash flows or financial position.
Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, or SAB 108—In September 2006, the SEC issued SAB 108 to address diversity in practice in quantifying financial statement misstatements. SAB 108 requires entities to quantify misstatements based on their impact on each of their financial statements and related disclosures. SAB 108 is effective as of the end of our 2006 fiscal year, allowing a one-time transitional cumulative effect adjustment to retained earnings as of January 1, 2006 for errors that were not previously deemed material, but are material under the guidance in SAB 108. The adoption of SAB 108 did not have a material impact on our consolidated results of operations, cash flows or financial position.
2. Acquisitions and Dispositions
Acquisitions
Acquisition of Various Gathering, Transmission and Processing Assets—In the fourth quarter of 2005, we entered into an agreement to purchase certain Federal Energy Regulatory Commission, or FERC, regulated pipeline and compressor station assets in Kansas, Oklahoma and Texas for approximately $50 million. We did not receive regulatory approval from the FERC to purchase the assets as non-jurisdictional gathering, but we are proceeding to file with the FERC for a certificate to operate these assets as intrastate pipeline. This acquisition is expected to close in the second half of 2007.
Acquisition of Additional Equity Interests—In December 2006, we acquired an additional 33.33 % interest in Main Pass Oil Gathering Company, or Main Pass, for approximately $30 million. We now own 66.67% of Main Pass with one other partner. Main Pass is a joint venture whose primary operation is a crude oil gathering pipeline system in the Gulf of Mexico.
In November 2006, we purchased the remaining 16% minority interest in Dauphin Island Gathering Partners, or DIGP, for $7 million. DIGP was owned 84% by us prior to this transaction, and subsequent to this transaction, is owned 100% by us. DIGP owns gathering and transmission assets in the Gulf Coast.
In December 2005, we purchased an additional 6.67% interest in Discovery Producer Services, LLC, or Discovery, from Williams Energy, LLC for a purchase price of $13 million. Discovery is an unconsolidated affiliate, which, prior to this transaction, was 33.33% owned by us, and subsequent to this transaction is 40% owned by us. Discovery owns and operates an interstate pipeline, a condensate handling facility, a cryogenic gas processing plant and other gathering assets in deepwater offshore Louisiana.
Dispositions
Disposition of Various Gathering, Transmission and Processing Assets—In December 2005, based upon management’s assessment of the probable disposition of certain plant, gathering and transmission assets, we classified certain of these assets as held for sale, recorded in other non-current assets, consisting primarily of property, plant and equipment totaling $58 million at December 31, 2005. Assets at one location, totaling $48 million as of December 31, 2005, were sold in the first quarter of 2006 for $76 million and we recognized a gain of $28 million. Assets at another location, totaling $9 million as of December 31, 2005, were sold in the first quarter of 2006 for $9 million and we recognized no gain or loss.
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Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
In August 2005, we sold certain gas gathering facilities in Kansas and Oklahoma for a sales price of approximately $11 million. No gain or loss was recognized.
In February 2005, we exchanged certain processing plant assets in Wyoming for certain gathering assets and related gathering contracts in Oklahoma of equivalent fair value.
In February 2005, we sold certain gathering, compression, fractionation, processing plant and transportation assets in Wyoming for approximately $28 million.
Disposition of Equity Interests—In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million. The cash proceeds from this transaction were received in February 2005 and loaned to Duke Energy and ConocoPhillips in amounts equal to their ownership percentages in the Company at that time. The loans were made under the terms of revolving credit facilities established in February 2005 with Duke Capital LLC, an affiliate of Duke Energy, and ConocoPhillips in the amounts of $767 million and $333 million, respectively. ConocoPhillips repaid its outstanding borrowings in full in March 2005. Duke Capital, LLC repaid its outstanding borrowings in full in July 2005.
Distribution of Canadian Business to Duke Energy—In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. These assets comprised a component of the Company for purposes of reporting discontinued operations. The results of operations and cash flows related to these assets have been reclassified to discontinued operations for all periods presented. The following is a summary of the net assets distributed to Duke Energy on the closing date of July 1, 2005 (millions):
Assets: | |||
Cash | $ | 44 | |
Accounts receivable | 18 | ||
Other assets | 1 | ||
Property, plant and equipment, net | 291 | ||
Goodwill | 18 | ||
Total assets | $ | 372 | |
Liabilities: | |||
Accounts payable | $ | 11 | |
Other current liabilities | 4 | ||
Current and long-term debt | 1 | ||
Deferred income taxes | 20 | ||
Other long-term liabilities | 12 | ||
Total liabilities | $ | 48 | |
Net assets of Canadian business distributed to Duke Energy | $ | 324 | |
We routinely sell assets that comprise a component of the Company, and are recorded as discontinued operations, but are not individually significant. The results of operations and cash flows related to these assets have been reclassified to discontinued operations for all periods presented.
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Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
There were no assets accounted for as discontinued operations for the year ended December 31, 2006. The following table sets forth selected financial information associated with assets accounted for as discontinued operations for the year ended December 31, 2005:
| 2005 | ||||
| (millions) | ||||
Operating revenues | $ | 35 | ||
Pre-tax operating income | $ | 4 | ||
Income tax expense | (1 | ) | ||
Income from discontinued operations | $ | 3 | ||
3. Agreements and Transactions with Affiliates
The following table represents the unrealized gains and unrealized losses on mark-to-market and hedging instruments with affiliates as of December 31:
| 2006 | 2005 | ||||||
| (millions) | |||||||
Duke Energy: | |||||||
Unrealized gains on mark-to-market and hedging instruments—current | $ | — | $ | 18 | |||
Unrealized gains on mark-to-market and hedging instruments—non-current | $ | — | $ | 19 | |||
Unrealized losses on mark-to-market and hedging instruments—current | $ | — | $ | (20 | ) | ||
Unrealized losses on mark-to-market and hedging instruments—non-current | $ | — | $ | (20 | ) | ||
ConocoPhillips: | |||||||
Unrealized gains on mark-to-market and hedging instruments—current | $ | 1 | $ | 9 | |||
Unrealized losses on mark-to-market and hedging instruments—current | $ | — | $ | (4 | ) | ||
The following table summarizes the transactions with Duke Energy, ConocoPhillips, and other unconsolidated affiliates as described below for the years ended December 31:
| 2006 | 2005 | |||||
| (millions) | ||||||
Duke Energy: | ||||||
Sales of natural gas and petroleum products to affiliates | $ | 41 | $ | 109 | ||
Transportation, storage and processing | $ | 18 | $ | 2 | ||
Purchases of natural gas and petroleum products from affiliates | $ | 137 | $ | 130 | ||
Operating and general and administrative expenses | $ | 30 | $ | 44 | ||
Interest income | $ | — | $ | 8 | ||
ConocoPhillips (a): | ||||||
Sales of natural gas and petroleum products to affiliates | $ | 2,677 | $ | 2,513 | ||
Transportation, storage and processing | $ | 12 | $ | 11 | ||
Purchases of natural gas and petroleum products from affiliates | $ | 492 | $ | 556 | ||
General and administrative expenses | $ | 5 | $ | — | ||
Unconsolidated affiliates: | ||||||
Sales of natural gas and petroleum products to affiliates | $ | 95 | $ | 163 | ||
Transportation, storage and processing | $ | 20 | $ | 20 | ||
Purchases of natural gas and petroleum products from affiliates | $ | 160 | $ | 144 | ||
| (a) | Includes ConocoPhillips’ 50% owned equity method investment, CP Chem. |
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Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
Spectra Energy and Duke Energy
Services Agreement—Under a services agreement, Duke Energy and certain of its subsidiaries provided us with various staff and support services, including information technology products and services, payroll, employee benefits, property taxes, media relations, printing and records management. Additionally, we used other Duke Energy services subject to hourly rates, including legal, insurance, internal audit, tax planning, human resources and security departments.
In connection with the Spectra spin, we will need to transfer responsibility for all services previously provided to us by Duke Energy to our corporate operations, or transition these services either to Spectra or to third party service providers.
Included on the consolidated balance sheets in other non-current assets—affiliates as of December 31, 2006, are insurance recovery receivables of $47 million, and included in accounts receivable—affiliates as of December 31, 2006 and 2005, are other receivables of $8 million and $39 million, respectively, from an insurance provider that is a subsidiary of Duke Energy. During the years ended December 31, 2006 and 2005, we recorded hurricane related business interruption insurance recoveries of $1 million and $3 million, respectively, included in the consolidated statements of operations and comprehensive income as sales of natural gas and petroleum products.
In the fourth quarter of 2006, an insurance provider that is a subsidiary of Duke Energy agreed to settle an insurance claim, related to a damaged underground storage facility, for approximately $21 million. We had recorded a receivable in 2005 related to this claim for approximately $4 million. Upon receipt of the cash in December 2006, we relieved the receivable and recorded business interruption insurance recoveries of approximately $16 million, included in the consolidated statements of operations and comprehensive income as transportation, storage and processing.
Commodity Transactions—We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to Duke Energy and Spectra Energy and their subsidiaries. Management anticipates continuing to purchase and sell these commodities and provide these services to Spectra Energy in the ordinary course of business.
ConocoPhillips
Long-term NGLs Purchases Contract and Transactions—We sell a portion of our residue gas and NGLs to ConocoPhillips and CP Chem, a 50% equity investment of ConocoPhillips (see Note 1). In addition, we purchase raw natural gas from ConocoPhillips. Under the NGL Output Purchase and Sale Agreement, or the CP Chem NGL Agreement, between us and CP Chem, CP Chem has the right to purchase at index-based prices substantially all NGLs produced by our various processing plants located in the Mid-Continent and Permian Basin regions, and the Austin Chalk area, which include approximately 40% of our total NGL production. The CP Chem NGL Agreement also grants CP Chem the right to purchase at index-based prices certain quantities of NGLs produced at processing plants that are acquired and/or constructed by us in the future in various counties in the Mid-Continent and Permian Basin regions, and the Austin Chalk area. The primary term of the agreement is effective until January 1, 2015. We anticipate continuing to purchase and sell these commodities and provide these services to ConocoPhillips and CP Chem in the ordinary course of business.
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
Transactions with other unconsolidated affiliates
In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million. The cash proceeds from this transaction were received in February 2005 and loaned to Duke Energy and ConocoPhillips in amounts equal to their ownership percentages in the Company at that time. The loans were made under the terms of revolving credit facilities established in February 2005 with Duke Capital LLC, an affiliate of Duke Energy, and ConocoPhillips in the amounts of $767 million and $333 million, respectively. ConocoPhillips repaid their outstanding borrowings in full in March 2005. Duke Capital LLC repaid their outstanding borrowings in full in July 2005.
We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to, unconsolidated affiliates. We anticipate continuing to purchase and sell these commodities and provide these services to unconsolidated affiliates in the ordinary course of business.
Estimates related to affiliates
Revenue for goods and services provided but not invoiced to affiliates is estimated each month and recorded along with related purchases of goods and services used but not invoiced. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. Actual invoices for the current month are issued in the following month and differences from estimated amounts are recorded. There are no material differences from the actual amounts invoiced subsequent to year end relating to estimated revenues and purchases recorded at December 31, 2006 and 2005.
4. Marketable Securities
Short-term and restricted investments—At December 31, 2006 and 2005, we had $437 million and $627 million, respectively, of short-term investments. These instruments are classified as available-for-sale securities under SFAS 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 the interest rates re-set on a daily, weekly or monthly basis.
In July 2005, ConocoPhillips contributed cash of $398 million to our Company. This cash was invested in financial instruments as described above. Under the terms of the amended and restated LLC Agreement, however, proceeds from this contribution were designated for the acquisition or improvement of property, plant and equipment. As this cash was to be used to acquire non-current assets, we had $0 and $264 million, respectively, classified as a long-term asset, as restricted investments, on the consolidated balance sheets at December 31, 2006 and 2005. At December 31, 2006 and 2005, we had restricted investments of $102 million and $100 million, respectively, consisting of collateral for DCP Partners’ term loan.
5. Inventories
Inventories by category were as follows as of December 31:
| 2006 | 2005 | |||||
| (millions) | ||||||
Natural gas held for resale | $ | 34 | $ | 43 | ||
NGLs | 53 | 67 | ||||
Total inventories | $ | 87 | $ | 110 | ||
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
6. Property, Plant and Equipment
Property, plant and equipment by classification was as follows as of December 31:
| Depreciable Life | 2006 | 2005 | ||||||||
| (millions) | ||||||||||
Gathering | 15–30 years | $ | 2,641 | $ | 2,503 | |||||
Processing | 25–30 years | 1,904 | 1,840 | |||||||
Transportation | 25–30 years | 1,217 | 1,223 | |||||||
Underground storage | 20–50 years | 119 | 103 | |||||||
General plant | 3–5 years | 146 | 138 | |||||||
Construction work in progress | 203 | 108 | ||||||||
| 6,230 | 5,915 | |||||||||
Accumulated depreciation | (2,361 | ) | (2,079 | ) | ||||||
Property, plant and equipment, net | $ | 3,869 | $ | 3,836 | ||||||
Depreciation expense for 2006 and 2005 was $275 million and $278 million, respectively. Interest capitalized on construction projects in 2006 and 2005, was approximately $3 million and $2 million, respectively. At December 31, 2006, we had non-cancelable purchase obligations of approximately $27 million for capital projects expected to be completed in 2007. In addition, property, plant and equipment includes $10 million and $13 million of non-cash additions for the years ended December 31, 2006 and 2005, respectively.
7. Goodwill and Other Intangibles
The changes in the carrying amount of goodwill are as follows for the years ended December 31:
| 2006 | 2005 | ||||||
| (millions) | |||||||
Goodwill, beginning of period | $ | 421 | $ | 452 | |||
Purchase price adjustments | — | (11 | ) | ||||
Foreign currency translation adjustments | — | (2 | ) | ||||
Distribution of Canadian business to Duke Energy | — | (18 | ) | ||||
Goodwill, end of period | $ | 421 | $ | 421 | |||
We perform an annual goodwill impairment test, and update the test during interim periods if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We use a discounted cash flow analysis supported by market valuation multiples to perform the assessment. Key assumptions in the analysis 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, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices.
We completed our annual goodwill impairment test as of August 31, 2006. We also tested goodwill for impairment in July 2005 upon the distribution of substantially all of our Canadian business to Duke Energy, in conjunction with the 50-50 Transaction. These goodwill impairment tests were performed by comparing our
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Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
reporting units’ estimated fair values to their carrying, or book, values. These valuations indicated our reporting units’ fair values were in excess of their carrying, or book, values; therefore, we have determined that there is no indication of impairment. There were no impairments of goodwill for the years ended December 31, 2006 and 2005.
During 2005, we recorded an adjustment to properly account for deferred taxes established as a result of purchase business combinations that occurred during 2001. As a result of this adjustment, goodwill and deferred income tax liabilities decreased by approximately $11 million and $3 million, respectively, and property, plant and equipment, net, increased by $8 million.
In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. Included in the distribution was $18 million of goodwill, which was determined based on the relative fair value of the Canadian business to the fair value of the Natural Gas Services reporting unit.
The gross carrying amount and accumulated amortization for commodity sales and purchases contracts are as follows for the years ended December 31:
| 2006 | 2005 | |||||||
| (millions) | ||||||||
Commodity sales and purchases contracts | $ | 132 | $ | 130 | ||||
Accumulated amortization | (74 | ) | (64 | ) | ||||
Commodity sales and purchases contracts, net | $ | 58 | $ | 66 | ||||
During the years ended December 31, 2006 and 2005, we recorded amortization expense associated with commodity sales and purchases contracts of $9 million. The remaining amortization periods for these intangibles range from less than one year to 20 years with a weighted average remaining period of approximately 7 years.
Estimated amortization for these contracts for the next five years and thereafter is as follows:
Estimated Amortization
| (millions) | |||
2007 | $ | 8 | |
2008 | 8 | ||
2009 | 8 | ||
2010 | 8 | ||
2011 | 7 | ||
Thereafter | 19 | ||
Total | $ | 58 | |
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
8. Investments in Unconsolidated Affiliates
We have investments in the following unconsolidated affiliates accounted for using the equity method:
2006 Ownership | December 31, | ||||||||
| 2006 | 2005 | ||||||||
| (millions) | |||||||||
Discovery Producer Services LLC | 40.00 | % | $ | 114 | $ | 102 | |||
Main Pass Oil Gathering Company | 66.67 | % | 47 | 13 | |||||
Sycamore Gas System General Partnership | 48.45 | % | 12 | 13 | |||||
Mont Belvieu I | 20.00 | % | 11 | 12 | |||||
Tri-States NGL Pipeline, LLC | 16.67 | % | 9 | 9 | |||||
Black Lake Pipe Line Company | 50.00 | % | 6 | 6 | |||||
Other unconsolidated affiliates | Various | 5 | 14 | ||||||
Total investments in unconsolidated affiliates | $ | 204 | $ | 169 | |||||
Discovery Producer Services LLC—Discovery Producer Services LLC, or Discovery, owns and operates a 600 MMcf/d interstate pipeline, a condensate handling facility, a cryogenic gas processing plant, and other gathering assets in deepwater offshore Louisiana. In December 2005, we acquired an additional 6.67% interest in Discovery from Williams Energy, LLC for a purchase price of $13 million, bringing our total ownership to 40%. The deficit between the carrying amount of the investment and the underlying equity of Discovery of $49 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Discovery.
Main Pass Oil Gathering Company—In December 2006, we acquired an additional 33.33% interest in Main Pass, a joint venture whose primary operation is a crude oil gathering pipeline system in the Main Pass East and Viosca Knoll Block areas in the Gulf of Mexico. We now own 66.67% of Main Pass with one other partner. Since Main Pass is not a variable interest entity, and we do not have the ability to exercise control, we continue to account for Main Pass under the equity method. The excess of the carrying amount of the investment over the underlying equity of Main Pass of $12 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Main Pass.
Sycamore Gas System General Partnership—Sycamore Gas System General Partnership, or Sycamore, is a partnership formed for the purpose of constructing, owning and operating a gas gathering and compression system in Carter County, Oklahoma. The excess of the carrying amount of the investment over the underlying equity of Sycamore of $9 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Sycamore.
Mont Belvieu I—Mont Belvieu I owns a 150 MBbl/d fractionation facility in the Mont Belvieu, Texas Market Center. The deficit between the carrying amount of the investment and the underlying equity of Mont Belvieu I of $11 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Mont Belvieu I.
Tri-States NGL Pipeline, LLC—Tri-States NGL Pipeline, LLC, or Tri-States, owns 169 miles of NGL pipeline, extending from a point near Mobile Bay, Alabama to a point near Kenner, Louisiana. The deficit between the carrying amount of the investment and the underlying equity of Tri-States of $3 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Tri-States. We own less than 20% interest in this Partnership, however, we exercise significant influence,
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
therefore, this investment is accounted for under the equity method of accounting in accordance with APB Opinion No. 18,“The Equity Method of Accounting for Investments in Common Stock.”
Black Lake Pipe Line Company—Black Lake Pipe Line Company, or Black Lake, owns a 317 mile long NGL pipeline, with a current capacity of approximately 40 MBbl/d. The pipeline receives NGLs from a number of gas plants in Louisiana and Texas. The NGLs are transported to Mont Belvieu fractionators. The deficit between the carrying amount of the investment and the underlying equity of Black Lake of $7 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Black Lake.
Fox Plant, LLC—In May 2006, we purchased the remaining 50% interest in Fox Plant, LLC, a limited liability company formed for the purpose of constructing, owning, and operating a gathering facility and gas processing plant in Carter County, Oklahoma. Subsequent to May 2006, Fox Plant, LLC was accounted for as a consolidated subsidiary. Fox Plant, LLC is included in other unconsolidated affiliates in the above table as of December 31, 2005.
TEPPCO Partners, L.P.—In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million.
Equity in earnings of unconsolidated affiliates amounted to the following for the years ended December 31:
| 2006 | 2005 | |||||||
| (millions) | ||||||||
Discovery Producer Services LLC | $ | 17 | $ | 11 | ||||
Main Pass Oil Gathering Company | 3 | 3 | ||||||
Sycamore Gas System General Partnership | (1 | ) | (1 | ) | ||||
Mont Belvieu I | (1 | ) | (1 | ) | ||||
Tri-States NGL Pipeline, LLC | 1 | 1 | ||||||
Black Lake Pipe Line Company | — | — | ||||||
TEPPCO Partners, L.P. | — | 8 | ||||||
Other unconsolidated affiliates | 1 | 1 | ||||||
Total equity in earnings of unconsolidated affiliates | $ | 20 | $ | 22 | ||||
The following summarizes combined financial information of unconsolidated affiliates for the years ended and as of December 31:
| 2006 | 2005 | |||||
| (millions) | ||||||
Income statement: | ||||||
Operating revenues | $ | 322 | $ | 328 | ||
Operating expenses | $ | 287 | $ | 312 | ||
Net income | $ | 42 | $ | 18 | ||
Balance sheet: | ||||||
Current assets | $ | 115 | $ | 133 | ||
Non-current assets | 724 | 740 | ||||
Current liabilities | 61 | 81 | ||||
Non-current liabilities | 7 | 6 | ||||
Net assets | $ | 771 | $ | 786 | ||
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Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
9. Estimated Fair Value of Financial Instruments
We have determined the following fair value amounts using available market information and appropriate valuation methodologies. Considerable judgment is required, however, in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.
| December 31, 2006 | December 31, 2005 | |||||||||||||||
Carrying Amount | Estimated Value | Carrying Amount | Estimated Value | |||||||||||||
| (millions) | ||||||||||||||||
Short-term investments | $ | 437 | $ | 437 | $ | 627 | $ | 627 | ||||||||
Restricted investments | 102 | 102 | 364 | 364 | ||||||||||||
Accounts receivable | 1,272 | 1,272 | 1,636 | 1,636 | ||||||||||||
Accounts payable | (1,624 | ) | (1,624 | ) | (2,119 | ) | (2,119 | ) | ||||||||
Net unrealized gains and losses on mark-to-market and hedging instruments | 22 | 22 | 14 | 14 | ||||||||||||
Current maturities of long-term debt | — | — | (300 | ) | (302 | ) | ||||||||||
Long-term debt | (2,115 | ) | (2,258 | ) | (1,760 | ) | (1,942 | ) | ||||||||
The fair value of short-term investments, restricted investments, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Unrealized gains and unrealized losses on mark-to-market and hedging instruments are carried at fair value.
The estimated fair values of current debt, including current maturities of long-term debt, and long-term debt, with the exception of DCP Partners’ long-term debt, are determined by prices obtained from market quotes. The carrying value of DCP Partners’ long-term debt approximates fair value, as the interest rate is variable and reflects current market conditions.
10. Asset Retirement Obligations
Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We recognize the fair value of a liability for an asset retirement obligation 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.
We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to take actions that would
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Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot be estimated and no obligation has been recorded.
The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The following table summarizes changes in the asset retirement obligation, included in other long-term liabilities in the consolidated balance sheets, for the years ended December 31:
| 2006 | 2005 | |||||||
| (millions) | ||||||||
Balance as of January 1 | $ | 50 | $ | 57 | ||||
Accretion expense | 3 | 3 | ||||||
Liabilities incurred | — | 1 | ||||||
Liabilities settled | (1 | ) | — | |||||
Distribution of Canadian business to Duke Energy | — | (10 | ) | |||||
Other | — | (1 | ) | |||||
Balance as of December 31 | $ | 52 | $ | 50 | ||||
11. Financing
Long-term debt was as follows at December 31:
| Principal/Discount | ||||||||
| 2006 | 2005 | |||||||
| (millions) | ||||||||
Debt securities: | ||||||||
Issued November 2001, interest at 5.750% payable semiannually, due November 2006 | $ | — | $ | 300 | ||||
Issued August 2000, interest at 7.875% payable semiannually, due August 2010 | 800 | 800 | ||||||
Issued January 2001, interest at 6.875% payable semiannually, due February 2011 | 250 | 250 | ||||||
Issued October 2005, interest at 5.375% payable semiannually, due October 2015 | 200 | 200 | ||||||
Issued August 2000, interest at 8.125% payable semiannually, due August 2030 | 300 | 300 | ||||||
Issued October 2006, interest at 6.450% payable semiannually, due November 2036 | 300 | — | ||||||
DCP Partners’ credit facility revolver, weighted average interest rate of 5.86% at December 31, 2006, due December 2010 | 168 | 110 | ||||||
DCP Partners’ credit facility term loan, interest rate of 5.47% at December 31, 2006, due December 2010 | 100 | 100 | ||||||
Fair value adjustments related to interest rate swap fair value hedges(a) | 4 | 7 | ||||||
Unamortized discount | (7 | ) | (7 | ) | ||||
Current portion of long-term debt | — | (300 | ) | |||||
Long-term debt | $ | 2,115 | $ | 1,760 | ||||
| (a) | See Note 12 for further discussion. |
Debt Securities—In October 2006, we issued $300 million principal amount of 6.45% Senior Notes due 2036, or the 6.45% Notes, for proceeds of approximately $297 million (net of related offering costs). The 6.45% Notes mature and become due and payable on November 3, 2036. We will pay interest semiannually on May 3
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Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
and November 3 of each year, commencing May 3, 2007. The proceeds from this offering were used to repay our 5.75% Senior Notes that matured on November 15, 2006.
In October 2005, we issued $200 million principal amount of 5.375% Senior Notes Due 2015, or 5.375% Notes, for proceeds of $197 million (net of related offering costs). The 5.375% Notes mature on October 15, 2015. We pay interest semiannually on April 15 and October 15 of each year, commencing April 15, 2006. The proceeds from this offering were used to repay the August 2005 term loan facility discussed below.
In August 2005, we repaid the $600 million 7.5% Notes that were due on August 16, 2005. We repaid a portion of this debt with available cash and proceeds from the issuance of commercial paper, and refinanced a portion of this debt with the August 2005 term loan facility discussed below.
The debt securities mature and become payable on the respective due dates, and are not subject to any sinking fund provisions. Interest is payable semiannually. The debt securities are unsecured and are redeemable at our option.
Credit Facilities with Financial Institutions—On April 29, 2005, we entered into a credit facility, or the Facility, to replace a $250 million 364-day facility that was terminated on April 29, 2005. The Facility is used to support our commercial paper program, and for working capital and other general corporate purposes. In December 2005, we amended the Facility to amend the definition of consolidated capitalization to include minority interest, which is referred to in these financial statements as non-controlling interest. In October 2006, we amended the Facility to modify the change of control provisions to allow for the Spectra spin, to extend the maturity April 29, 2012, to amend the pricing, to remove the interest coverage covenant and to incorporate other minor revisions. Any outstanding borrowings under the Facility at maturity may, at our option, be converted to an unsecured one-year term loan. The Facility is a $450 million revolving credit facility, all of which can be used for letters of credit. The Facility requires us to maintain at all times a debt to total capitalization ratio of less than or equal to 60%. Draws on the Facility bear interest at a rate equal to, at our option and based on our current debt rating, either (1) LIBOR plus 0.35% per year for the initial 50% usage or LIBOR plus 0.45% per year if usage is greater than 50% or (2) the higher of (a) the Wachovia Bank prime rate per year and (b) the Federal Funds rate plus 0.5% per year. The Facility incurs an annual facility fee of 0.1% based on our credit rating on the drawn and undrawn portions. As of December 31, 2006, there were no borrowings or commercial paper outstanding, and there was approximately $5 million in letters of credit drawn against the Facility. As of December 31, 2005, there were no borrowings or commercial paper outstanding, and there were no letters of credit drawn against the Facility.
In August 2005, we entered into a credit agreement, or the Term Loan Facility, where we made a one-time request to borrow $200 million in the form of a term loan. We used this Term Loan Facility to repay a portion of our $600 million 7.5% Notes that matured on August 16, 2005. The Term Loan Facility was repaid in October 2005 with proceeds from the 5.375% Notes.
On December 7, 2005, DCP Partners entered into a 5-year credit agreement, or the DCP Partners’ Credit Agreement, with a $250 million revolving credit facility and a $100 million term loan facility. The DCP Partners’ Credit Agreement matures on December 7, 2010. At December 31, 2006 and 2005, there was $168 million and $110 million, respectively, outstanding on the revolving credit facility and $100 million outstanding on the term loan facility. The term loan facility is fully collateralized by investments in high-grade securities, which are classified as restricted investments on the accompanying consolidated balance sheet. Outstanding letters of credit on the DCP Partners’ Credit Agreement were less than $1 million as of
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Table of Contents
Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
December 31, 2006, and there were no letters of credit outstanding at December 31, 2005. The DCP Partners’ Credit Agreement requires DCP Partners to maintain at all times (commencing with the quarter ending March 31, 2006) a leverage ratio (the ratio of DCP Partners’ consolidated indebtedness to its consolidated EBITDA, in each case as is defined by the DCP Partners’ Credit Agreement) of less than or equal to 4.75 to 1.0 (and on a temporary basis for not more than three consecutive quarters following the acquisition of assets in the midstream energy business of not more than 5.25 to 1.0); and maintain at the end of each fiscal quarter an interest coverage ratio (defined to be the ratio of adjusted EBITDA, as defined by the DCP Partners’ Credit Agreement to be earnings before interest, taxes and depreciation and amortization and other non-cash adjustments, for the four most recent quarters to interest expense for the same period) of greater than or equal to 3.0 to 1.0. Indebtedness under the revolving credit facility bears interest, at our option, at either (1) the higher of Wachovia Bank’s prime rate or the federal funds rate plus 0.50% or (2) LIBOR plus an applicable margin, which ranges from 0.27% to 1.025% dependent upon the leverage level or credit rating. As of December 31, 2006, the $100 million term loan facility bears interest at LIBOR plus a rate per annum of 0.15%. The revolving credit facility incurs an annual facility fee of 0.08% to 0.35%, depending on the applicable leverage level or debt rating. This fee is paid on drawn and undrawn portions of the revolving credit facility.
Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2006:
Debt Maturities
| (millions) | ||||
2010 | $ | 1,068 | ||
2011 | 250 | |||
Thereafter | 804 | |||
| 2,122 | ||||
Unamortized discount | (7 | ) | ||
Long-term debt | $ | 2,115 | ||
12. Risk Management and Hedging Activities, Credit Risk and Financial Instruments
Commodity price risk—Our principal operations of gathering, processing, compression, transportation and storage of natural gas, and the accompanying operations of fractionation, transportation, gathering, treating, processing, storage and trading and marketing of NGLs create commodity price risk exposure due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. As an owner and operator of natural gas processing and other midstream assets, we have an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas contracts entered into to purchase and process raw natural gas. Risk is also dependent on the types and mechanisms for sales of natural gas and NGLs, and related products produced, processed, transported or stored.
Energy trading (market) risk—Certain of our subsidiaries are engaged in the business of trading energy related products and services, including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and we may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments.
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
Interest rate risk—We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to hedge interest rate risk associated with our debt. Our primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical rates.
Credit risk—Our principal customers range from large, natural gas marketing services to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately 40% of our NGL production is committed to ConocoPhillips and CP Chem under an existing 15-year contract, which expires in 2015. This concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We may use master collateral agreements to mitigate credit exposure. Collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with our credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a satisfactory form.
As of December 31, 2006, we held cash or letters of credit of $83 million to secure future performance of financial or physical contracts, and had deposited with counterparties $7 million of such collateral to secure our obligations to provide future services or to perform under financial contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, trading and hedging contracts. In many cases, we and our counterparties’ publicly disclose credit ratings, which may impact the amounts of collateral requirements.
Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.
Commodity hedging strategies—Historically, we have used commodity cash flow hedges, as specifically defined in SFAS 133, to reduce the potential negative impact that commodity price changes could have on our earnings and our ability to adequately plan for cash needed for debt service, capital expenditures and tax distributions. Our current strategy is to use cash flow hedges only for commodity price risk related to DCP Partners’ operations. Some of the assets operated by DCP Partners generate cash flows that are subject to volatility from fluctuating commodity prices. As a publicly traded master limited partnership, an important component of the strategy of DCP Partners is to generate consistent cash flow from its operations in order to pay distributions to its unitholders. For operations other than those of DCP Partners, we do not currently anticipate using cash flow hedges in the near future, because management believes cash flows will be sufficient to fund our business.
Commodity cash flow hedges—We have executed a series of derivative financial instruments, which have been designated as cash flow hedges of the price risk associated with forecasted sales of natural gas, NGLs and
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DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
condensate through 2010, and the price risk associated with forecasted sales of condensate during 2011, related to assets of DCP Partners. Because of the strong correlation between NGL prices and crude oil prices, and the lack of liquidity in the NGL financial market, we have used crude oil swaps to hedge NGL price risk.
For the year ended December 31, 2006, amounts recognized as comprehensive income in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments were gains of $4 million, and amounts recognized for the effects of any ineffectiveness were insignificant for the year ended December 31, 2006. For the year ended December 31, 2005, amounts recognized in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments and for the effects of any ineffectiveness were not significant. During the year ended December 31, 2006, we reclassified $1 million in net gains (net of minority interest of $2 million) to the consolidated statements of operations and comprehensive income as a result of settlements. No derivative gains or losses were reclassified from AOCI to current period earnings as a result of a change in the probability of forecasted transactions occurring, which would cause us to discontinue hedge treatment. The deferred balance in AOCI was a gain of $3 million at December 31, 2006, and was insignificant at December 31, 2005. As of December 31, 2006, $1 million of deferred net gains on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings; however, due to the volatility of the commodities markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.
Commodity fair value hedges—We use fair value hedges to hedge exposure to changes in the fair value of an asset or a liability (or an identified portion thereof) that is attributable to fixed price risk. We may hedge producer price locks (fixed price gas purchases) and market locks (fixed price gas sales) to reduce our exposure to fixed price risk via swapping the fixed price risk for a floating price position (New York Mercantile Exchange or index based).
For the years ended December 31, 2006 and 2005, the gains or losses representing the ineffective portion of our fair value hedges were not significant. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. We did not have any firm commitments that no longer qualified as fair value hedge items and, therefore, did not recognize an associated gain or loss.
Interest rate cash flow hedges—During 2006, DCP Partners entered into interest rate swap agreements to convert $125 million of the indebtedness on their revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. All interest rate swaps expire on December 7, 2010 and re-price prospectively approximately every 90 days. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense. The interest rate swap agreements have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation. The effective portions of changes in fair value are recognized in AOCI in the accompanying consolidated balance sheets. For the year ended December 31, 2006, amounts recognized in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments were not significant, and there was no ineffectiveness recorded for the year ended December 31, 2006. At December 31, 2006, the gains deferred in AOCI related to these swaps were insignificant. At December 31, 2006, the amount of deferred net gains on derivative instruments in AOCI that are expected to be reclassified into earnings during the next 12 months as the hedged transactions occur are insignificant; however, due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
Prior to issuing fixed rate debt in August 2000, we entered into, and terminated, treasury locks and interest rate swaps to lock in the interest rate prior to it being fixed at the time of debt issuance. The losses realized on these agreements, which were terminated in 2000, are deferred into AOCI and amortized against interest expense over the life of the respective debt. The amount amortized to interest expense during the years ended December 31, 2006 and 2005, was $1 million for both periods. The deferred balance was a loss of $7 million and $8 million at December 31, 2006 and 2005, respectively. Approximately $1 million of deferred net losses related to these instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the underlying hedged interest expense transaction occurs.
Interest rate fair value hedges—In October 2001, we entered into an interest rate swap to convert $250 million of fixed-rate debt securities, which were issued in August 2000, to floating rate debt. The interest rate fair value hedge was at a floating rate based on a six-month LIBOR, which was re-priced semiannually through the date of maturity, August 2005.
In August 2003, we entered into two additional interest rate swaps to convert $100 million of fixed-rate debt securities issued in August 2000 to floating rate debt. These interest rate fair value hedges are at a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030. The swaps meet conditions, which permit the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swaps no ineffectiveness will be recognized. As of December 31, 2006 and 2005, the fair value of the interest rate swaps was a $4 million and $8 million asset, respectively, which is included in the consolidated balance sheets as unrealized gains or losses on mark-to-market and hedging instruments with offsets to the underlying debt included in current maturities of long-term debt and long-term debt.
Commodity derivatives—trading and marketing—Our trading and marketing program is designed to realize margins related to fluctuations in commodity prices and basis differentials, and to maximize the value of certain storage and transportation assets. Certain of our subsidiaries are engaged in the business of trading energy related products and services including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. We manage our trading and marketing portfolio with strict policies, which limit exposure to market risk, and require daily reporting to management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate daily value at risk.
13. Stock-Based Compensation
DCP Midstream, LLC Long-Term Incentive Plan, or 2006 Plan—Relative Performance Units—RPU’s generally cliff vest at the end of eight years, consisting of a three year performance period and a five year deferral period. The number of RPU’s that will ultimately vest range from 0% to 200% of the outstanding RPU’s, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance payout is determined by the compensation committee of our board of directors. At the end of the performance period, based on the market value of the RPU’s, we will create an account for each grantee in our deferred compensation plan. Payment of the grantee’s deferred compensation account will occur after a five year deferral period, the value of which is based on the value of the participant’s investment elections during the deferral period. Each RPU includes a dividend or distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the RPUs for the year ended December 31, 2006,
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DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
was not significant. At December 31, 2006, there was approximately $1 million of unrecognized compensation expense related to the RPU’s, which was calculated using an estimated forfeiture rate of 64%, and is expected to be recognized over a weighted-average period of 7.0 years. The following tables presents information related to RPUs:
| Units | Grant Date Weighted- Average Per Unit | Measurement Weighted- Average Per Unit | ||||||
Outstanding at December 31, 2005 | — | $ | — | |||||
Granted | 44,080 | $ | 42.89 | |||||
Outstanding at December 31, 2006 | 44,080 | $ | 42.89 | $ | 50.78 | |||
Expected to vest | 15,869 | $ | 42.89 | $ | 50.78 | |||
Strategic Performance Units—SPU’s generally cliff vest at the end of three years. The number of SPU’s that will ultimately vest range from 0% to 150% of the outstanding SPU’s, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance payout is determined by the compensation committee of our board of directors. Each SPU includes a dividend or distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the SPUs for the year ended December 31, 2006, was approximately $1 million. At December 31, 2006 there was approximately $3 million of unrecognized compensation expense related to the SPU’s, which was calculated using estimated forfeiture rates ranging from 12% to 32%, and is expected to be recognized over a weighted-average period of 2.0 years. The following tables presents information related to SPUs:
| Units | Grant Date Weighted- Average Per Unit | Measurement Weighted- Average Per Unit | ||||||
Outstanding at December 31, 2005 | — | $ | — | |||||
Granted | 84,960 | $ | 42.92 | |||||
Outstanding at December 31, 2006 | 84,960 | $ | 42.92 | $ | 50.78 | |||
Expected to vest | 65,949 | $ | 42.92 | $ | 50.78 | |||
The estimate of RPU’s and SPU’s that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore the amounts of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations and comprehensive income.
Phantom Units—Phantom Units generally cliff vest at the end of five years. Each Phantom Unit includes a dividend or distribution equivalent right, which is paid quarterly in arrears. Expense related to the Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006 there was approximately $1 million of unrecognized compensation expense related to the Phantom Units, which was calculated using an
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
estimated forfeiture rate of 19%, and is expected to be recognized over a weighted-average period of 4.0 years. The following table presents information related to Phantom Units:
| Units | Grant Weighted- Average Per Unit | Measurement Weighted- Average Per Unit | ||||||
Outstanding at December 31, 2005 | — | $ | — | |||||
Granted | 17,460 | $ | 42.95 | |||||
Outstanding at December 31, 2006 | 17,460 | $ | 42.95 | $ | 50.78 | |||
Expected to vest | 14,143 | $ | 42.95 | $ | 50.78 | |||
DCP Partners’ Phantom Units—The DCP Partners’ Phantom Units constitute a notional unit equal to the fair value of a common unit of DCP Partners, which generally cliff vest at December 31, 2008. Each DCP Partners’ Phantom Unit includes a distribution equivalent right, which is paid quarterly in arrears. Expense related to the DCP Partners’ Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006 there was approximately $1 million of unrecognized compensation expense related to the DCP Partners’ Phantom Units, which was calculated using estimated forfeiture rates ranging from 12% to 32%, and is expected to be recognized over a weighted-average period of 2.0 years. The following table presents information related to the DCP Partners’ Phantom Units:
| Units | Grant Weighted- Average Per Unit | Measurement Weighted- Average Per Unit | ||||||
Outstanding at December 31, 2005 | — | $ | — | |||||
Granted | 47,750 | $ | 28.60 | |||||
Outstanding at December 31, 2006 | 47,750 | $ | 28.60 | $ | 34.55 | |||
Expected to vest | 34,920 | $ | 28.60 | $ | 34.55 | |||
During the year ended December 31, 2006, no awards under the 2006 Plan were forfeited, vested or settled.
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
DCP Partners’ Long-Term Incentive Plan, or DCP Partners’ Plan—Performance Units—Performance Units generally cliff vest at the end of a three year performance period. The number of Performance Units that will ultimately vest range from 0% to 150% of the outstanding Performance Units, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance percentage payout is determined by the compensation committee of DCP Partners’ board of directors. Each Performance Unit includes a distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the Performance Units for the year ended December 31, 2006, was not significant. At December 31, 2006, there was approximately $1 million of unrecognized compensation expense related to the Performance Units, which is expected to be recognized over a weighted-average period of 2.0 years. The following tables presents information related to the Performance Units:
| Units | Grant Weighted- Average Per Unit | Measurement Weighted- Average Per Unit | |||||||
Outstanding at December 31, 2005 | — | $ | — | ||||||
Granted | 40,560 | $ | 26.96 | ||||||
Forfeited | (17,470 | ) | $ | 26.96 | |||||
Outstanding at December 31, 2006 | 23,090 | $ | 26.96 | $ | 34.55 | ||||
Expected to vest | 23,090 | $ | 26.96 | $ | 34.55 | ||||
The estimate of Performance Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations and comprehensive income.
Phantom Units—Of the Phantom Units, 16,700 units will vest upon the three year anniversary of the grant date and 8,000 units vest ratably over three years. Each Phantom Unit includes a distribution equivalent right which is paid quarterly in arrears. Expense related to the Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006, estimated unrecognized compensation expense related to the Phantom Units was not significant. The following tables presents information related to the Phantom Units:
| Units | Grant Weighted- Average Per Unit | Measurement Weighted- Average Per Unit | |||||||
Outstanding at December 31, 2005 | — | $ | — | ||||||
Granted | 35,900 | $ | 24.05 | ||||||
Forfeited | (11,200 | ) | $ | 24.05 | |||||
Outstanding at December 31, 2006 | 24,700 | $ | 24.05 | $ | 34.55 | ||||
Expected to vest | 24,700 | $ | 24.05 | $ | 34.55 | ||||
The estimate of Phantom Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate. Therefore the amount of unrecognized
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DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations and comprehensive income.
All awards issued under the 2006 Plan and the DCP Partners’ Plan are intended to be settled in cash upon vesting. Compensation expense is recognized ratably over each vesting period, and will be remeasured quarterly for all awards outstanding until the units are vested. The fair value of all awards is determined based on the closing price of the relevant underlying securities at each measurement date. During the year ended December 31, 2006, no awards were vested or settled.
Duke Energy 1998 Plan—Under its 1998 Plan, Duke Energy granted certain of our key employees stock options, phantom stock awards, stock-based performance awards and other stock awards to be settled in shares of Duke Energy’s common stock. Upon execution of the 50-50 Transaction in July 2005, our employees incurred a change in status from Duke Energy employees to non-employees. As a result, we ceased accounting for these awards under APB 25 and FIN 44, and began accounting for these awards in accordance with EITF 96-18, using the fair value method prescribed in SFAS 123. No awards have been and we do not expect to settle any awards granted under the 1998 Plan with cash.
Stock Options —Under the 1998 Plan, the exercise price of each option granted could not be less than the market price of Duke Energy’s common stock on the date of grant. Vesting periods range from immediate to four years with a maximum option term of 10 years. Effective July 1, 2005, these options were accounted for in accordance with EITF 96-18, using the fair value method prescribed in SFAS 123. As a result, compensation expense subsequent to July 1, 2005, is recognized based on the change in the fair value of the stock options at each reporting date until vesting.
The following tables show information regarding options to purchase Duke Energy’s common stock granted to our employees.
| Shares | Weighted- Exercise | Weighted- (years) | Aggregate Intrinsic (millions) | ||||||||
Outstanding at December 31, 2005 | 2,592,567 | $ | 29.46 | 5.2 | |||||||
Exercised | (367,088 | ) | $ | 21.15 | |||||||
Forfeited | (124,417 | ) | $ | 29.96 | |||||||
Outstanding at December 31, 2006 | 2,101,062 | $ | 30.89 | 4.1 | $ | 12 | |||||
Exercisable at December 31, 2006 | 1,941,212 | $ | 32.30 | 4.0 | $ | 9 | |||||
Expected to vest | 155,630 | $ | 13.77 | 6.2 | $ | 3 | |||||
The total intrinsic value of options exercised during the year ended December 31, 2006 and 2005, was approximately $3 million and $2 million, respectively. As of December 31, 2006, all compensation expense related to these awards has been recognized.
There were no options granted during the years ended December 31, 2006 or 2005.
Stock-Based Performance Awards —Stock-based performance awards outstanding under the 1998 Plan vest over three years if certain performance targets are achieved. Duke Energy awarded 160,910 shares during the
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DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
year ended December 31, 2005. There were no stock-based performance awards granted during the year ended December 31, 2006.
The following table summarizes information about stock-based performance awards activity during the year ended December 31, 2006:
| Shares | Grant Weighted- Average Per Unit | Measurement Weighted- Average Per Unit | |||||||
Outstanding at December 31, 2005 | 342,453 | $ | 23.88 | ||||||
Forfeited | (40,835 | ) | $ | 23.85 | |||||
Outstanding at December 31, 2006 | 301,618 | $ | 23.90 | $ | 33.21 | ||||
Expected to vest | 289,161 | $ | 23.90 | $ | 33.21 | ||||
As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was approximately $1 million, which is expected to be recognized over a weighted-average period of less than 1 year. No awards were granted, vested or canceled during the year ended December 31, 2006.
Phantom Stock Awards —Phantom stock awards outstanding under the 1998 Plan vest over periods from one to five years. Duke Energy awarded 128,850 shares during the year ended December 31, 2005. There were no phantom stock awards granted during the year ended December 31, 2006.
The following table summarizes information about phantom stock awards activity during the year ended December 31, 2006:
| Shares | Grant Weighted- Average Per Unit | Measurement Weighted- Average Per Unit | |||||||
Outstanding at December 31, 2005 | 241,216 | $ | 24.22 | ||||||
Vested | (54,150 | ) | $ | 23.90 | |||||
Forfeited | (22,378 | ) | $ | 24.29 | |||||
Outstanding at December 31, 2006 | 164,688 | $ | 24.34 | $ | 33.21 | ||||
Expected to vest | 157,886 | $ | 24.34 | $ | 33.21 | ||||
The total fair value of the phantom stock awards that vested during the year ended December 31, 2006 and 2005 was approximately $2 million and less than $1 million, respectively. As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was approximately $1 million, which is expected to be recognized over a weighted-average period of 2.7 years. No awards were granted or canceled during the year ended December 31, 2006.
Other Stock Awards —Other stock awards outstanding under the 1998 Plan vest over periods from one to five years. Duke Energy granted 3,000 other stock awards during the year ended December 31, 2005. There were no other stock awards granted during the year ended December 31, 2006.
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DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
The following table summarizes information about other stock awards activity during the year ended December 31, 2006:
| Shares | Grant Weighted- Average Per Unit | Measurement Weighted- Average Per Unit | |||||||
Outstanding at December 31, 2005 | 45,400 | $ | 21.73 | ||||||
Vested | (10,600 | ) | $ | 21.73 | |||||
Forfeited | (13,200 | ) | $ | 21.73 | |||||
Outstanding at December 31, 2006 | 21,600 | $ | 21.73 | $ | 33.21 | ||||
Expected to vest | 20,038 | $ | 21.73 | $ | 33.21 | ||||
The total fair value of the other stock awards that vested during the years ended December 31, 2006 and 2005 was not significant. As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was not significant, and is expected to be recognized over a weighted-average period of less than 1 year. No awards were granted or canceled during the year ended December 31, 2006.
14. Benefits
All Company employees who are 18 years old and work at least 20 hours per week are eligible for participation in our 401(k) and retirement plan, to which we contributed 4% of each eligible employee’s qualified earnings, through December 31, 2006. Effective January 1, 2007, we began contributing a range of 4% to 7% of each eligible employee’s qualified earnings, based on years of service. Additionally, we match employees’ contributions in the plan up to 6% of qualified earnings. During 2006 and 2005, we expensed plan contributions of $15 million.
We offer certain eligible executives the opportunity to participate in the DCP Midstream LP’s Non-Qualified Executive Deferred Compensation Plan. This plan allows participants to defer current compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The plan also has make-whole provisions for plan participants who may otherwise be limited in the amount that we can contribute to the 401(k) plan on the participant’s behalf. All amounts contributed to or earned by the plan’s investments are held in a trust account for the benefit of the participants. The trust and the liability to the participants are part of our general assets and liabilities, respectively.
15. Income Taxes
We are structured as a limited liability company, which is a pass-through entity for United States income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns. The income tax expense related to this corporation is included in our income tax expense, along with state, local, franchise, and margin taxes of the limited liability company and other subsidiaries. In addition, until July 1, 2005, we had Canadian subsidiaries that were subject to Canadian income taxes. Taxes associated with these subsidiaries have been reclassified to discontinued operations for year ended December 31, 2005.
In May 2006, the State of Texas enacted a new margin-based franchise tax law that replaces the existing franchise tax. This new tax is commonly referred to as the Texas margin tax. Corporations, limited partnerships,
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DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the new tax.
As a result of the change in Texas franchise law, our tax status in the state of Texas has changed from non-taxable to taxable. The tax is considered an income tax for purposes of adjustments to the deferred tax liability. The tax is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas margin tax becomes effective for franchise tax reports due on or after January 1, 2008. The 2008 tax will be based on revenues earned during the 2007 fiscal year.
The Texas margin tax is assessed at 1% of taxable margin apportioned to Texas. We have computed taxable margin as total revenue less cost of goods sold. Based on information currently available, we recorded a deferred tax liability of $18 million in 2006. The deferred tax liability is recorded as non-current in the consolidated balance sheets as of December 31, 2006, and as a non-cash offset to income tax expense in the consolidated statements of operations and comprehensive income for the year ended December 31, 2006.
Income tax expense consists of the following for the years ended December 31:
| 2006 | 2005 | ||||||
| (millions) | |||||||
Current: | |||||||
Federal | $ | 5 | $ | 9 | |||
State | 1 | 2 | |||||
Deferred: | |||||||
Federal | — | — | |||||
State | 17 | (2 | ) | ||||
Total income tax expense | $ | 23 | $ | 9 | |||
Temporary differences for our gross deferred tax assets of $4 million primarily relate to basis differences between property, plant and equipment, and investments in unconsolidated affiliates. Temporary differences for our gross deferred tax liabilities of $17 million primarily relate to basis differences between property, plant and equipment.
Our effective tax rate differs from statutory rates, primarily due to our being structured as a limited liability company, which is a pass-through entity for United States income tax purposes, while being treated as a taxable entity in certain states.
16. Commitments and Contingent Liabilities
Litigation—The midstream industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. A number of these cases are now being brought as class actions. We are currently named as defendants in some of these cases. Management believes we have meritorious defenses to these cases and, therefore, will continue to defend them vigorously. These class actions, however, can be costly and time consuming to defend. We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.
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DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
In December 2006, El Paso E&P Company, L.P., or El Paso, filed a lawsuit against one of our subsidiaries, DCP Assets Holding, LP and an affiliate of DCP Midstream GP, LP, in District Court, Harris County, Texas. The litigation stems from an ongoing commercial dispute involving DCP Midstream Partners’ Minden processing plant that dates back to August 2000. El Paso claims damages, including interest, in the amount of $6 million in the litigation, the bulk of which stems from audit claims under our commercial contract. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated results of operations, financial position or cash flows.
In November 2006, we received a demand associated with the alleged migration of acid gas from a storage formation into a third party producing formation. The plaintiff seeks a broad array of remedies, including a purchase of the plaintiff’s lease rights. We conducted an investigation using a geotechnical consulting firm and believe that acid gas is migrating from the storage formation into the producing formation. We could be liable for damages related to the diminution in market value to the leases, if any, caused by the migration of the acid gas. At this time, it is not possible to predict the ultimate damages, if any, that we might incur in connection with this matter.
Management currently believes that these matters, taken as a whole, and after consideration of amounts accrued, insurance coverage and other indemnification arrangements, will not have a material adverse effect upon our consolidated results of operations, financial position or cash flows.
General Insurance—In 2005, we carried all of our insurance coverage with an affiliate of Duke Energy. Beginning in 2006, we elected to carry only property and excess liability insurance coverage with an affiliate of Duke Energy and an affiliate of ConocoPhillips, however, effective August 2006, we no longer carry insurance coverage with an affiliate of Duke Energy. Our remaining insurance coverage is with an affiliate of ConocoPhillips and a third party insurer. Our insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from our 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, and (4) 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. Property insurance deductibles are currently $1 million for onshore or non-hurricane related incidents or up to $5 million per occurrence for hurricane related incidents. We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Casualty insurance deductibles are currently $1 million per occurrence. The cost of our general insurance coverages increased over the past year reflecting the adverse conditions of the insurance markets.
During the third quarter of 2004, certain assets, located in the Gulf Coast, were damaged as a result of hurricane Ivan. The resulting losses are expected to be covered by insurance, subject to applicable deductibles for property and business interruption. Insurance recovery receivables related to hurricane Ivan included on the consolidated balance sheets in other non-current assets—affiliates as of December 31, 2006, are $25 million, and included in accounts receivable—affiliates as of December 31, 2006 and 2005, are $3 million and $28 million, respectively, from an insurance provider that is a subsidiary of Duke Energy.
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
During the third quarter of 2005, hurricanes Katrina and Rita forced us to temporarily shut down our operations at certain assets located in Alabama, Louisiana, Texas and New Mexico, however, substantially all of our facilities have resumed pre-hurricane levels of capacity utilization. Several of our assets sustained property damage, including some of our operating equipment on a platform in the Gulf of Mexico. A portion of the resulting lost revenues and property damages are covered by our insurance, subject to applicable deductibles. The financial impact of recent hurricanes has increased market rates for insurance coverage; however, these increases did not have a material adverse effect on our consolidated results of operations, financial position or cash flows. Insurance recovery receivables related to hurricane Katrina included on the consolidated balance sheets in other non-current assets—affiliates as of December 31, 2006 are $21 million, and included in accounts receivable—affiliates as of December 31, 2006 and 2005, are $2 million and $5 million, respectively, from an insurance provider that is a subsidiary of Duke Energy. Included in other non-current assets—affiliates as of December 31, 2006, are insurance recovery receivables related to hurricane Rita of $1 million at December 31, 2006. The balance at December 31, 2005, was not significant. Based on recent negotiations, we have reclassified a portion of these hurricane insurance receivables as non-current at December 31, 2006.
During the years ended December 31, 2006 and 2005, we recorded business interruption insurance recoveries related to these hurricanes of $1 million and $3 million, respectively, in the consolidated statements of operations and comprehensive income as sales of natural gas and petroleum products.
Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.
On July 20, 2006, the State of New Mexico Environment Department issued Compliance Orders to us that list air quality violations during the past five years at three of our owned or operated facilities in New Mexico. The orders allege a number of violations related to excess emissions from January 2001 to date and further require us to install flares for smokeless operations and to use the flares only for emergency purposes. The Compliance Orders seek a civil penalty but did not request a specific amount. We intend to contest these allegations. Management does not believe this will result in a material impact on our consolidated results of operations, cash flows or financial position.
Other Commitments and Contingencies—We utilize assets under operating leases in several areas of operations. Consolidated rental expense, including leases with no continuing commitment, amounted to $37 million and $36 million in 2006 and 2005, respectively. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term.
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2006:
Minimum Rental Payments
| (millions) | ||||
2007 | $ | 25 | ||
2008 | 19 | |||
2009 | 14 | |||
2010 | 14 | |||
2011 | 12 | |||
Thereafter | 39 | |||
Total gross payments | 123 | |||
Sublease receipts | (2 | ) | ||
Total net payments | $ | 121 | ||
17. Guarantees and Indemnifications
In September 2005, we signed a corporate guaranty, which was amended in December 2005 upon our purchase of an additional interest in the related unconsolidated affiliate, pursuant to which we are the guarantor of a maximum of $10 million of construction obligations. The original guaranty was $22 million as of December 31, 2005, and was reduced by construction payments of $12 million during the year ended December 31, 2006. The guaranty will expire upon completion and payment for construction of a pipeline expected to be completed during 2007. The fair value of this guarantee is not significant to our consolidated results of operations, financial position or cash flows.
We periodically enter into agreements for the acquisition or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation, breaches of representations, warranties and covenants, or other liabilities related to the assets being acquired or divested. Claims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The effective periods on these indemnification provisions generally have terms of one to five years, although some are longer. Our maximum potential exposure under these indemnification agreements can vary depending on the nature of the claim and the particular transaction. We are unable to estimate the total maximum potential amount of future payments under indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities. At both December 31, 2006 and 2005, we had a liability of approximately $1 million recorded for known liabilities related to outstanding indemnification provisions.
18. Subsequent Events
In March 2007, DCP Midstream Partners entered into a definitive agreement to acquire certain gathering and compression assets located in southern Oklahoma from Anadarko Petroleum Corporation, or Anadarko, for approximately $180 million, subject to customary closing conditions and certain regulatory approvals. DCP Midstream Partners paid an earnest deposit of $9 million when they entered into this agreement. If Anadarko terminates because DCP Midstream Partners materially breaches their representations, warranties or covenants under this agreement, Anadarko may retain this earnest deposit as liquidated damages. This deposit will be
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements — Continued
Years Ended December 31, 2006 and 2005
applied against the purchase price at the closing of this transaction, which is expected to occur in the second quarter of 2007. The remaining purchase price is expected to be funded by the issuance of DCP Midstream Partners’ partnership units and by proceeds from DCP Midstream Partners’ credit facility.
On January 24, 2007, DCP Partners announced the declaration of a cash distribution of $0.43 per unit, payable on February 14, 2007, to unitholders of record on February 7, 2007.
On January 2, 2007, Duke Energy created two separate publicly traded companies by spinning off their natural gas businesses, including their 50% ownership interest in us, to Duke Energy shareholders. As a result of this transaction, we are no longer 50% owned by Duke Energy. Duke Energy’s 50% ownership interest in us was transferred to a new company, Spectra Energy. We do not expect this transaction to have a material effect on our operations.
On January 1, 2007, we changed our name from Duke Energy Field Services, LLC to DCP Midstream, LLC, to coincide with the Spectra spin.
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Index to Financial Statements
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Schedule II—Consolidated Valuation and Qualifying Accounts and Reserves for the years ended December 31, 2006 and 2005
| Balance at Beginning of Period | Increases Charged to Expense | Charged to Other Accounts(b) | Deductions(c) | Balance at End of Period | |||||||||||||
| ($ in millions) | |||||||||||||||||
December 31, 2006 | |||||||||||||||||
Allowance for doubtful accounts | $ | 4 | $ | — | $ | — | $ | (1 | ) | $ | 3 | ||||||
Environmental | 13 | 3 | — | (4 | ) | 12 | |||||||||||
Litigation | 5 | 6 | — | (2 | ) | 9 | |||||||||||
Other (a) | 6 | — | — | (2 | ) | 4 | |||||||||||
| $ | 28 | $ | 9 | $ | — | $ | (9 | ) | $ | 28 | |||||||
December 31, 2005 | |||||||||||||||||
Allowance for doubtful accounts | $ | 4 | $ | 1 | $ | — | $ | (1 | ) | $ | 4 | ||||||
Environmental | 17 | 5 | — | (9 | ) | 13 | |||||||||||
Litigation | 8 | 1 | 2 | (6 | ) | 5 | |||||||||||
Other (a) | 8 | 11 | (2 | ) | (11 | ) | 6 | ||||||||||
| $ | 37 | $ | 18 | $ | — | $ | (27 | ) | $ | 28 | |||||||
| (a) | Principally consists of other contingency reserves, which are included in other current liabilities. |
| (b) | Consists of other contingency and litigation reserves reclassified between accounts. |
| (c) | Principally consists cash payments, collections, reserve reversals and liabilities settled. |
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Index to Financial Statements
| Exhibit No. | Exhibit Description | |
| 2.1 | Separation and Distribution Agreement by and between Duke Energy Corporation and Spectra Energy Corp, dated as of December 13, 2006 (filed as Exhibit 2.1 to Form 8-K of Spectra Energy Corp on December 15, 2006) | |
| 2.2 | Reorganization Agreement by and among ConocoPhillips, Duke Capital LLC and Duke Energy Field Services, LLC, dated as of May 26, 2005 (filed with Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10.4) | |
| 2.2.1 | First Amendment to Reorganization Agreement by and among ConocoPhillips, Duke Capital LLC and Duke Energy Field Services, LLC, dated as of June 30, 2005 (filed with Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10.4.1) | |
| 2.2.2 | Second Amendment to Reorganization Agreement by and among ConocoPhillips, Duke Capital LLC and Duke Energy Field Services, LLC, dated as of July 11, 2005 (filed with Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10.4.2) | |
| 2.3 | Amended and Restated Combination Agreement, dated as of September 20, 2001, among Duke Energy Corporation, 3058368 Nova Scotia Company, 3946509 Canada Inc. and Westcoast Energy Inc. (filed with Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2001, File No. 1-4928, as Exhibit 10.7) | |
| 2.4 | Spectra Energy Support Agreement dated as of January 1, 2007, between Spectra Energy Corp, Duke Energy Canada Call Co. and Duke Energy Canada Exchangeco Inc. (filed as Exhibit 2.2 to Form S-3 of Spectra Energy Corp on January 17, 2007) | |
| 2.5 | Spectra Energy Voting and Exchange Trust Agreement dated as of January 1, 2007, between Spectra Energy Corp, Duke Energy Canada Exchangeco Inc. and Computershare Trust Company, Inc. (filed as Exhibit 2.3 to Form S-3 of Spectra Energy Corp on January 17, 2007) | |
| 2.6 | Plan of Arrangement, as approved by the Supreme Court of British Columbia by final order dated December 15, 2006 (filed as Exhibit 2.4 to Form S-3 of Spectra Energy Corp on January 17, 2007) | |
| 3.1 | Amended and Restated Certificate of Incorporation of Spectra Energy Corp (filed as Exhibit 3.1 to Form 8-K of Spectra Energy Corp on December 15, 2006) | |
| 3.2 | Amended and Restated By-laws of Spectra Energy Corp (filed as Exhibit 3.2 to Form 8-K of Spectra Energy Corp on December 15, 2006) | |
| 4.1 | Senior Indenture between Duke Capital Corporation and the Chase Manhattan Bank, dated as April 1, 1998 (filed with Registration Statement on Form S-3 of Duke Capital Corporation, File No. 333-71297 as Exhibit 4.1) | |
| 10.1 | Tax Matters Agreement by and among Duke Energy Corporation, Spectra Energy Corp, and The Other Spectra Energy Parties, dated as of December 13, 2006 (filed as Exhibit 10.1 to Form 8-K of Spectra Energy Corp on December 15, 2006) | |
| 10.2 | Transition Services Agreement by and between Duke Energy Corporation and Spectra Energy Corp, dated as of December 13, 2006 (filed as Exhibit 10.2 to Form 8-K of Spectra Energy Corp on December 15, 2006) | |
| 10.3 | Employee Matters Agreement by and between Duke Energy Corporation and Spectra Energy Corp, dated as of December 13, 2006 (filed as Exhibit 10.3 to Form 8-K of Spectra Energy Corp on December 15, 2006) | |
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Index to Financial Statements
| Exhibit No. | Exhibit Description | |
| 10.4 | Purchase and Sale Agreement, dated as of February 24, 2005, by and between Enterprise GP Holdings LP and Duke Energy Field Services, LLC (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-25) | |
| 10.5 | Term Sheet Regarding the Restructuring of Duke Energy Field Services LLC, dated as of February 23, 2005, between Duke Energy Corporation and ConocoPhillips (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-26) | |
| 10.6 | Second Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC by and between ConocoPhillips Gas Company and Duke Energy Enterprises Corporation, dated as of July 5, 2005 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2005, File No. 1-4928, as Exhibit 10.5) | |
| 10.7 | Limited Liability Company Agreement of Gulfstream Management & Operating Services, LLC, dated as of February 1, 2001 between Duke Energy Gas Transmission Corporation and Williams Gas Pipeline Company (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2002, File No. 1-4928, as Exhibit 10-18) | |
| 10.8 | $800,000,000 364-Day Credit Agreement, dated as of June 29, 2005, among Duke Capital LLC, the banks listed therein, JPMorgan Chase Bank, N.A., as Administrative Agent, and Barclays Bank, PLC, as Syndication Agent (filed with Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10.3) | |
| 10.9 | Amended and Restated Credit Agreement, dated June 29, 2006, among Duke Capital LLC, The Banks Listed Herein, JPMorgan Chase Bank, N.A., as Administrative Agent, and Wachovia Bank, National Association, as Syndication Agent (filed with Form 8-K of Duke Capital LLC, File No. 0-23977, July 6, 2006, as Exhibit 10.1) | |
| 10.10 | $600,000,000 Amended and Restated Credit Agreement, dated as of June 30, 2005, among Duke Capital LLC, the banks listed therein, JPMorgan Chase Bank, N.A., as Administrative Agent, and Wachovia Bank, National Association, as Syndication Agent (filed with Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10.2). | |
| 10.11 | Loan Agreement, dated as of February 25, 2005 between Duke Energy Field Services, LLC and Duke Capital LLC (filed with Form 10-Q of Duke Energy Corporation for the quarter ended March 31, 2005, File No. 1-4928, as Exhibit 10.3) | |
| 10.12 | $350,000,000 Credit Agreement, as of November 28, 2006, among Duke Capital LLC, the banks listed therein, Citibank, N.A., as Administrative Agent, and Barclays Bank PLC, as Syndication Agent (filed with Form 8-K of Duke Capital LLC, dated December 6, 2006, File No. 000-23977, as Exhibit 10.1) | |
| +10.13 | Spectra Energy Corp Directors’ Savings Plan (filed as Exhibit 10.1 to Form 8-K of Spectra Energy Corp on December 22, 2006) | |
| +10.14 | Spectra Energy Corp Executive Savings Plan (filed as Exhibit 10.2 to Form 8-K of Spectra Energy Corp on December 22, 2006) | |
| +10.15 | Spectra Energy Corp Executive Cash Balance Plan (filed as Exhibit 10.3 to Form 8-K of Spectra Energy Corp on December 22, 2006) | |
| +10.16 | Form of Change of Control Severance Agreements (filed as Exhibit 10.4 to Form 8-K of Spectra Energy Corp on December 22, 2006) | |
| +10.17 | Spectra Energy Corp 2007 Long-Term Incentive Plan (filed with Amendment No. 3 to Form 10, dated December 6, 2006, File No. 1-33007, as Exhibit 10.1) | |
| +*10.18 | Form of Non-Qualified Stock Option Agreement pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan | |
| +*10.19 | Form of Phantom Stock Award Agreement pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan | |
| *12 | Computation of Ratio of Earnings to Fixed Charges. | |
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Index to Financial Statements
| Exhibit No. | Exhibit Description | |
| *21.1 | Subsidiaries | |
| *23.1 | Consent of Independent Registered Public Accounting Firm. | |
| *23.2 | Consent of Independent Registered Public Accounting Firm. | |
| *23.3 | Consent of Independent Registered Public Accounting Firm. | |
| *23.4 | Consent of Independent Auditors. | |
| *24.1 | Power of Attorney | |
| *31.1 | Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| *31.2 | Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| *32.1 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| *32.1 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| * | Filed herewith. |
| + | Denotes management contract or compensatory plan or arrangement. |