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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007 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 |
Securities registered pursuant to Section 12(g) of the Act: None.
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 ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x
Estimated aggregate market value of the common equity held by nonaffiliates of the registrant at June 30, 2007: $16,400,000,000.
Number of shares of Common Stock, $0.001 par value, outstanding at February 19, 2008: 632,536,965
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2008 Annual Meeting of Shareholders are incorporated by reference in Part III.
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SPECTRA ENERGY CORP
FORM 10-K FOR THE YEAR ENDED
DECEMBER 31, 2007
| Item |
Page | |||
| PART I. | ||||
| 1. |
4 | |||
| 4 | ||||
| 5 | ||||
| 5 | ||||
| 5 | ||||
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| 1A. |
23 | |||
| 1B. |
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| 2. |
28 | |||
| 3. |
29 | |||
| 4. |
29 | |||
| PART II. | ||||
| 5. |
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 30 | ||
| 6. |
30 | |||
| 7. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
32 | ||
| 7A. |
64 | |||
| 8. |
65 | |||
| 9. |
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
137 | ||
| 9A. |
137 | |||
| 9B. |
138 | |||
| PART III. | ||||
| 10. |
138 | |||
| 11. |
138 | |||
| 12. |
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 138 | ||
| 13. |
Certain Relationships and Related Transactions, and Director Independence |
138 | ||
| 14. |
138 | |||
| PART IV. | ||||
| 15. |
139 | |||
| 140 | ||||
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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; |
| • | outcomes of litigation and regulatory investigations, proceedings or inquiries; |
| • | 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 or other hostilities; |
| • | changes in environmental, safety and other laws and regulations; |
| • | 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; |
| • | increases in the cost of goods and services required to complete capital projects; |
| • | declines in 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 effects of accounting pronouncements issued periodically by accounting standard-setting bodies; |
| • | conditions of the capital markets during the periods covered by the forward-looking statements; and |
| • | 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. |
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, through its subsidiaries and equity affiliates (collectively, Spectra Energy), owns and operates a large and diversified portfolio of complementary natural gas-related energy assets and is one of North America’s leading natural gas infrastructure 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. 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 Maritime Provinces in Canada 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), one of the largest natural gas gatherers and processors in the United States, based in Denver, Colorado. Spectra Energy’s operations are subject to various federal, state, provincial and local laws and regulations.
Spectra Energy’s natural gas pipeline systems consist of approximately 18,000 miles of transmission pipelines. Spectra Energy’s proportional throughput for its pipelines totaled 3,642 trillion British thermal units (TBtu) in 2007 compared to 3,260 TBtu in 2006. 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 272 billion cubic feet (Bcf) of storage capacity in the United States and Canada.
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Spin-off from Duke Energy Corporation
On January 2, 2007, Duke Energy Corporation (Duke Energy) completed the spin-off of Spectra Energy. Duke Energy contributed the 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 then wholly owned subsidiary, Spectra Energy Capital, LLC (Spectra Capital). Duke Energy contributed its ownership interests in Spectra Capital to Spectra Energy and all of the outstanding common stock of Spectra Energy was distributed to Duke Energy’s shareholders.
Subsequent to the reorganization and spin-off of Spectra Energy from Duke Energy, Spectra Energy manages its business in four reportable segments: U.S. Transmission, Distribution, Western Canada Transmission & Processing, and Field Services. The remainder of Spectra Energy’s business operations is presented as “Other” and consists of unallocated corporate costs, wholly owned captive insurance subsidiaries, employee benefit plan assets and liabilities and other miscellaneous activities. The following sections describe the operations of each of Spectra Energy’s businesses. For financial information on Spectra Energy’s business segments, see Part II, Item 8. Financial Statements and Supplementary Data, Note 4 of Notes to Consolidated Financial Statements.
Spectra Energy’s U.S. Transmission business provides transportation and storage of natural gas for customers in various regions of the Eastern and Southeastern United States and the Maritime Provinces in Canada. Spectra Energy’s U.S. pipeline systems consist of more than 13,500 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. U.S. Transmission’s proportional throughput for its pipelines totaled 2,202 TBtu in 2007 compared to 1,930 TBtu in 2006. 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. Interruptible transportation services are provided on a short-term or seasonal basis. In the course of providing transportation services, U.S. 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.
Most of U.S. Transmission’s pipeline and storage operations are regulated by the Federal Energy Regulatory Commission (FERC) and are subject to the jurisdiction of various federal state and local environmental agencies.
In July 2007, Spectra Energy completed its initial public offering (IPO) of Spectra Energy Partners, LP (Spectra Partners), a newly formed, midstream energy master limited partnership which is part of the U.S. Transmission segment. Spectra Energy retained an 83% equity interest in Spectra Partners, which currently owns 100% of East Tennessee, 50% of Market Hub Partners, LLC (MHP) and a 24.5% interest in Gulfstream. Spectra Energy retained a 50% direct ownership interest in MHP and a 25.5% direct ownership interest in Gulfstream. Spectra Partners is a separate, publicly traded entity which trades on the New York Stock Exchange under the symbol “SEP.”
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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 8,700 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 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 73 Bcf.
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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 Maritimes & Northeast Pipeline. The system consists of approximately 1,100 miles of pipeline with six compressor stations.
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 21 compressor stations. East Tennessee has a liquefied natural gas (LNG) storage facility in Tennessee with a total working capacity of 1.1 Bcf. East Tennessee also connects to storage facilities in Virginia owned by Spectra Energy that have a working gas capacity of approximately 5 Bcf.
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Spectra Energy has an effective 83% ownership interest in East Tennessee through its ownership of Spectra Partners.
Maritimes & Northeast Pipeline
Maritimes & Northeast Pipeline’s gas transmission system is operated primarily through Maritimes & Northeast Pipeline, LP and Maritimes & Northeast Pipeline, LLC, which are owned 78% by Spectra Energy. The 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 an effective 46% investment in Gulfstream, a 700-mile interstate natural gas pipeline system operated jointly by Spectra Energy and The Williams Companies, Inc. Gulfstream transports natural gas from Mississippi and Alabama, crossing the Gulf of Mexico to markets in central and southern Florida. Gulfstream has one compressor station. Gulfstream is owned 25.5% by Spectra Energy, 24.5% by Spectra Partners and 50% by The Williams Companies, Inc.
Market Hub Partners, LLC
Spectra Energy has an effective 92% ownership interest in Market Hub Partners, LLC (MHP), which 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 is a general partnership in which Spectra Energy and Spectra Partners each have a 50% interest.
Saltville Gas Storage L.L.C.
Saltville Gas Storage Company L.L.C. (Saltville) owns and operates natural gas storage facilities with a total storage capacity of approximately 5 Bcf. The storage facilities interconnect with Virginia Gas Pipeline Company and East Tennessee. This salt cavern facility offers high deliverability capabilities and is strategically located near markets in Tennessee, Virginia and North Carolina. Saltville is currently capable of delivering up to 275 million cubic feet of natural gas per day to the surrounding region.
In December 2007, Spectra Energy announced an agreement to sell Saltville and the P-25 Pipeline (a 72-mile, eight-inch natural gas pipeline) to Spectra Partners for $107 million, consisting of newly issued partnership units and approximately $5 million in cash. The transaction is expected to close during the second quarter of 2008, pending required regulatory approvals.
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Competition
Spectra Energy’s U.S. Transmission 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. Factors that influence the demand for natural gas include 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.
Customers and Contracts
In general, Spectra Energy’s U.S. Transmission pipelines provide transportation and storage services to local distribution companies (LDCs), electric power generators, exploration and production companies, and 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 the pipelines or injected or withdrawn from Spectra Energy’s storage facilities plus a small variable component that is based on volumes transported to recover variable costs.
Spectra Energy also provides interruptible transportation and storage services where customers can use capacity if it is available at the time of the request. Payments under these services are based on volumes transported or stored. These operations also provide a variety of other value-added services including natural gas parking, loaning and balancing services to meet customers’ needs.
Spectra Energy provides distribution services in Canada through its subsidiary, Union Gas Limited (Union Gas). Union Gas owns pipeline, storage and compression facilities used in the transportation, storage and distribution of natural gas. Union Gas’ system consists of approximately 37,000 miles of distribution main and service 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 2,800 miles of high-pressure 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.
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Union Gas’ 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.
Competition
As Union Gas’ distribution business is regulated by the OEB, it is not generally subject to third-party competition within its distribution franchise area, although as a result of a 2006 decision by the OEB, physical bypass of Union Gas’ facilities even within its distribution franchise area may be permitted. In addition, other companies could enter Union Gas’ markets or regulations could change.
Union Gas competes with other forms of energy available to its customers and end-users, including electricity, coal, propane and fuel oils. Factors that influence the demand for natural gas include 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.
In November 2006, the OEB issued a decision 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. For these unregulated services, Union Gas will compete against third-party storage providers for storage on the basis of price, terms of service, and flexibility and reliability of service. Existing storage services to customers within Union Gas’ franchise area will continue to be provided at cost-based rates and will not be subject to third-party competition.
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.
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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.
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. A substantial amount of Union Gas’ annual transportation and storage revenue is generated by fixed demand charges. The average term of these contracts is approximately five years, with the longest contract term being almost 20 years.
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 natural gas liquids (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 U.S. 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. Throughput for the BC Pipeline totaled 596 TBtu in 2007 compared to 594 TBtu in 2006.
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 approximately 1,600 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 (the Income Fund), a Canadian income trust. The Midstream business consists of 13 natural gas processing plants and approximately 1,000 miles of gathering pipelines.
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The Empress NGL Marketing business provides NGL extraction, fractionation, transportation, storage and marketing services to 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 where propane, butane and condensate are loaded for shipping or transferred into product sales pipelines, two NGL storage facilities, and an NGL marketing and gas supply business. The Empress fractionation plant is located in Empress, Alberta.
Competition
Western Canada Transmission & Processing businesses compete with third-party midstream companies, exploration and production companies and pipelines in the transportation of natural gas and the extraction and marketing of NGL products. 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.
Natural gas competes with other forms of energy available to Western Canada Transmission & Processing’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors affect the demand for natural gas in the areas served by Spectra Energy.
In addition to the fee for service pipeline and gathering and processing businesses, Spectra Energy competes with other NGL extraction facilities at Empress, Alberta for the right to extract and purchase NGLs from natural gas shippers on the TransCanada pipeline system. To extract and acquire NGLs, Spectra Energy must be competitive in the premium or fee it pays to natural gas shippers.
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 natural gas trading hub; and (ii) transportation services
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primarily to downstream markets in the Pacific Northwest (both United States and Canada.) Major customer segments include LDCs, electric power generators, exploration and production companies, gas marketers, and industrial and commercial end users.
The majority of transportation services are provided under firm agreements, which provide for fixed reservation charges that are paid monthly regardless of actual volumes transported on the pipeline, plus a small variable component that is based on volumes transported to recover variable costs. Spectra Energy’s BC Pipeline also provides interruptible transportation services where customers can use capacity if it is available at the time of request and payments under these services are based on volumes transported.
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 services.
The NGL extraction operation at Empress, Alberta has capacity to produce approximately 50,000 barrels of NGLs per day comprised of approximately 50% ethane, 32% propane, 12% butanes and 6% condensate. After NGLs are extracted, Spectra Energy fractionates the NGLs into ethane, propane, butane, and condensate and sells these products into the marketplace. 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 and crude diluent markets. The prices Spectra Energy can obtain for these products is affected by numerous factors including competition, weather, transportation costs and supply and demand factors.
Field Services consists of Spectra Energy’s 50% investment in DCP Midstream, which is accounted for as an equity investment. DCP Midstream gathers and processes natural gas, and fractionates, markets and trades NGLs. ConocoPhillips owns the remaining 50% interest in DCP Midstream.
DCP Midstream operates in 25 states in the United States. 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 eight major natural gas producing regions: Permian Basin, Mid-Continent, Rocky Mountain, East Texas-North Louisiana, Barnett Shale, Gulf Coast, South Texas and Central Texas. DCP Midstream owns or operates approximately 58,000 miles of gathering and transmission pipe, with approximately 37,000 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 located in Southeast Texas.
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’s operating results are significantly affected by changes in average NGL and crude oil prices, which increased approximately 18% and 10%, respectively, in 2007 compared to 2006. DCP Midstream closely monitors the risks associated with these price changes. See Item 7. 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.
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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/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 are effective until January 1, 2015. In 2007, ConocoPhillips and Chevron Phillips Chemical Company LLC, combined, represented approximately 21% 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 from these arrangements 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 from these arrangements is directly related to the volume of natural gas that flows through its systems and is not directly dependent on commodity prices. |
| • | Keep-whole and wellhead purchase arrangement. DCP Midstream gathers or purchases 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 price difference between NGLs and natural gas prices, representing the theoretical gross margin for processing liquids from natural gas. |
As defined by the terms of the above arrangements, DCP Midstream also 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 engines, valves, fittings, polyethylene plastic pipe, gas meters and other consumables.
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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 Spectra Energy to maximize the efficiency of supply networks where applicable. DCP Midstream performs its own supply chain management function.
Global growth in the energy sector, particularly in North America, and rising international demand have led to increased demand levels and increased costs of steel and other materials 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 2008 through 2010 compared to the previous three year period. The increasing costs and extended lead times are expected to primarily affect Spectra Energy’s expansion project program.
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.
Most of Spectra Energy’s U.S. gas transmission pipeline and storage operations are regulated by the 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 and abandonment of 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 marketing affiliates and require that U.S. interstate pipelines function independently of their marketing affiliates.
The FERC may propose and implement new rules and regulations affecting interstate natural gas transmission and storage 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. Transmission and the DCP Midstream operations are subject to the jurisdiction of the Environmental Protection Agency (EPA) and state and local environmental agencies. See “Environmental Matters” for a discussion of environmental regulation. Spectra Energy’s U.S. interstate natural gas pipelines and certain of DCP Midstream’s gathering and transmission pipelines are also subject to the regulations of the Department of Transportation (DOT) concerning pipeline safety.
The natural gas transmission and distribution, and approximately two-thirds of the storage operations in Canada are subject to regulation by the NEB or the provincial agencies in Canada, such as the OEB. These agencies have jurisdiction similar to the FERC for regulating rates, the terms and conditions of service, the construction of additional facilities and acquisitions. 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 the 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 natural gas gathering and processing activities are not subject to FERC regulation.
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Spectra Energy is subject to U.S. federal, state and local laws and regulations, as well as Canadian national and provincial 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. |
| • | 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 effects 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. |
| • | The Canadian Environmental Protection Act, which among other things, will govern the reduction of greenhouse gas emissions from Spectra Energy operations in Canada. Regulations to be promulgated under the Act will set emission-intensity reduction targets and deadlines for fixed emission caps for nitrogen oxides, sulphur oxides, volatile organic compounds and particulate matter. |
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| • | The Alberta Climate Change and Emissions Management Act, which, pursuant to regulations which came into effect in 2007, requires certain facilities to meet annual reductions in emission intensity targets starting in 2007. The Act is applicable to Spectra Energy’s Empress and Nevis facilities in Alberta. |
For more information on environmental matters involving Spectra Energy, including possible liability and capital costs, see Item 8. Financial Statements and Supplementary Data, Notes 5 and 18 of Notes to Consolidated Financial Statements.
Except to the extent discussed in Notes 5 and 18, compliance with international, federal, state 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 Spectra Energy’s competitive position, consolidated results of operations, financial position and cash flows.
For a discussion of Spectra Energy’s Canadian operations and the risks associated with them, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency Risk, and Notes 4 and 20 of Notes to Consolidated Financial Statements.
Spectra Energy had approximately 5,100 employees as of December 31, 2007, including approximately 3,300 employees outside of the United States, all in Canada. In addition, DCP Midstream, Spectra Energy’s joint venture with ConocoPhillips, employed approximately 2,500 employees as of such date. Approximately 1,500 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, through its subsidiaries, reached agreements with all bargaining units with agreements subject to renewal in 2007.
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.
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Terms used to describe Spectra Energy’s business are defined below.
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 the 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.
Distribution System. The system of pipelines, services and equipment which carry or control the supply of natural gas from the point of local supply to customers.
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.
Fractionation/Fractionate. The process of separating liquid hydrocarbons from natural gas into propane, butane, ethane and other related products.
Frac-spread. The price difference between NGLs and natural gas prices, representing the theoretical gross margin for processing liquids from natural gas.
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.
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.
Natural Gas Liquids (NGLs). Liquid hydrocarbons extracted during the processing of natural gas. Principal commercial NGLs include butanes, propane, natural gasoline and ethane.
Organic Growth. Growth due to the expansion or optimization of existing assets.
Residue Gas. Gas remaining after the processing of natural gas.
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Supply Push/Market Pull. “Supply push” is when producers agree to pay to transport specified volumes of natural gas in order to support the construction of new pipelines. “Market pull” is taking gas away from established liquid supply points and building pipeline transportation capacity to satisfy end-user demand in new markets or demand growth in existing markets.
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.
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The following table sets forth information regarding Spectra Energy’s executive officers. With the exception of Mr. Capps, each of the individuals set forth below assumed their current position immediately before Spectra Energy’s listing on the New York Stock Exchange in January 2007.
| Name |
Age | Position | ||
| Fred J. Fowler |
62 | President and Chief Executive Officer, Director | ||
| Martha B. Wyrsch |
50 | President and Chief Executive Officer – Spectra Energy Transmission, Director | ||
| Gregory L. Ebel |
43 | Group Executive and Chief Financial Officer | ||
| William S. Garner, Jr. |
58 | Group Executive, General Counsel and Secretary | ||
| Alan N. Harris |
54 | Group Executive and Chief Development Officer | ||
| Allen C. Capps |
37 | Vice President and Treasurer | ||
| Sabra L. Harrington |
45 | 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 (Duke Energy) from November 2002 until April 2006. Mr. Fowler serves as Chairman of the Board of Directors of DCP Midstream Partners, LP and is also on the Board of Directors of DCP Midstream, LLC.
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 from January 2004 until March 2005. Prior to then, Ms. Wyrsch served in various senior legal roles for Duke Energy. Prior to joining Duke Energy, Ms. Wyrsch served as Vice President, General Counsel and Secretary for KN Energy Inc. from August 1997 until September 1999. Ms. Wyrsch currently serves as Chairman of the Board of Trustees of Spectra Energy Income Fund and Chairman of the Board of Directors of Spectra Energy Partners, LP.
Gregory L. Ebel served as President of Union Gas Limited 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 Duke Energy’s acquisition of Westcoast Energy, Inc. He served in that position from March 2002 until November 2002. Mr. Ebel also serves on the Board of Trustees of Spectra Energy Income Fund and on the Board of Directors of DCP Midstream, LLC.
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. (now Merrill Lynch Incorporated), 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. Mr. Garner also serves on the Board of Trustees of Spectra Energy Income Fund and on the Board of Directors of Spectra Energy Partners, LP.
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, Duke Energy Gas Transmission from March 2002 until January 2003 and Vice President, Controller & Strategic Planning, Duke Energy Gas Transmission from April 1999 until March 2002.
Allen C. Capps served as Director of Finance of EPCO, Inc. from April 2006 until December 2007 before assuming his current position. Prior to then, Mr. Capps served as Interim Controller of TEPPCO Partners, LP
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from June 2005 until April 2006, Director of Technical Accounting and Compliance from April 2004 until June 2005 and Manager of Technical Accounting and Compliance from April 2003 until April 2004. Mr. Capps served as Senior Auditor with Ernst & Young LLP from January 2002 until March 2003.
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.
Discussed below are the more significant risk factors relating to Spectra Energy.
Reductions in demand for natural gas and low market prices of commodities affect Spectra Energy’s operations and cash flows.
Declines in demand for natural gas as a result of economic downturns and conservation efforts in Spectra Energy’s gas service territories 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. Revenues and cash flows would also be affected by lower market prices of natural gas and NGLs.
Lower demand for natural gas and lower prices for natural gas and NGLs result from multiple factors that affect the markets where Spectra Energy operates, 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 NGLs. |
The lack of availability of natural gas resources may cause customers to contract with alternative service providers, which could materially adversely affect Spectra Energy’s revenues, 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 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 service suppliers, thereby reducing their reliance on Spectra Energy’s services, which in turn would materially adversely affect Spectra Energy’s revenues, earnings and cash flows.
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Investments and projects located in Canada expose Spectra Energy to fluctuations in currency rates that may adversely affect results of operations and cash flows.
Spectra Energy is exposed to foreign currency risk from investments and operations in Canada. As of December 31, 2007, a 10% devaluation in the currency exchange rate of the Canadian dollar would result in an estimated loss on the translation of Canadian currency earnings of $31 million. The consolidated balance sheet would be negatively affected by $511 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 losses in earnings and reduced cash flows.
Spectra Energy has gathering and processing operations that consist of contracts to buy and sell commodities, including contracts for natural gas, NGLs and other commodities that are settled by the delivery of the commodity or cash. Spectra Energy is primarily exposed to market price fluctuations of NGL prices in the Field Services segment and to frac-spreads in the Empress operations in Canada. Since NGL prices historically track crude oil prices, Spectra Energy discloses its NGL price sensitivities in terms of crude oil price changes. Based on a sensitivity analysis as of December 31, 2007, at Spectra Energy’s forecasted NGL-to-oil price relationships, a $10 per barrel move in oil prices would affect Spectra Energy’s annual pre-tax earnings by approximately $135 million in 2008 ($120 million from Field Services and $15 million from U.S. Transmission). With respect to the frac-spread risk related to Empress processing and NGL marketing activities in Western Canada, as of December 31, 2007, a $0.50 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 $16 million on an annual basis in 2008. These hypothetical calculations consider estimated production levels, but do not consider other potential effects that might result from such changes in commodity prices. The actual effect of commodity price changes on Spectra Energy’s earnings could be significantly different than these estimates.
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 FERC and by various authorities under federal, state and local environmental laws. Spectra Energy’s natural gas assets and operations in Canada are also subject to regulation by federal, provincial and local authorities including the NEB and the OEB and by various federal and provincial authorities under 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, construct, expand and operate facilities, issue equity or debt securities, and pay dividends.
In addition, regulators in both the U.S. and Canada have taken actions to strengthen market forces in the gas pipeline industry, which have led to increased competition. In a number of key markets, natural gas pipeline and storage operators 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 effect on Spectra Energy’s business, earnings, financial condition and cash flows.
Execution of Spectra Energy’s capital projects subjects Spectra Energy to construction risks, increases in labor costs and materials, and other risks that may adversely affect financial results.
A significant portion of Spectra Energy’s growth is accomplished through the construction of new pipelines and storage facilities as well as the expansion of existing facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:
| • | the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms |
| • | the availability of skilled labor, equipment, and materials to complete expansion projects; |
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| • | potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project, |
| • | impediments on Spectra Energy’s ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms; and |
| • | the ability to construct projects within anticipated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials, labor, or other factors beyond Spectra Energy’s control, that may be material. |
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. As a result, new facilities may not achieve expected investment return, which could adversely affect results of operations, financial position or cash flows.
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 significant injury, 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. Therefore, should any of these risks materialize, it could have a material adverse effect on Spectra Energy’s business, earnings, financial condition and cash flows.
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 require significant expenditures, including expenditures for cleanup 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 or 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.
Canada is a signatory to and has ratified the Kyoto Protocol to the United Nations Framework Convention on Climate Change. In 2007, the Province of Alberta adopted legislation which require existing large emitters (facilities releasing 100,000 tons or more of GHG emissions annually) to reduce their annual emissions intensity by 12% beginning July 1, 2007. The effect of this Alberta legislation did not materially affect consolidated results of operations, financial position or cash flows. Should the federal and provincial governments in Canada implement programs to reduce greenhouse gas emissions, Spectra Energy’s businesses in
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Canada may be obligated to reduce emissions, purchase emission credits and/or pay a tax on carbon emissions. Due to the substantial uncertainty regarding what additional plans, if any, federal and provincial governments in Canada will implement and whether these plans will apply to Spectra Energy’s facilities, Spectra Energy cannot estimate the potential effects of greenhouse gas regulation in Canada on business, earnings, financial condition and cash flows.
Spectra Energy is involved in numerous legal proceedings, the outcome of which are uncertain, and resolution adverse to Spectra Energy could negatively affect results of operations, financial condition and cash flows.
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, particularly if Spectra Energy or its rated subsidiaries are unable to maintain an investment-grade credit rating, which could adversely affect cash flows or restrict business.
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. 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 could decrease.
Spectra Energy maintains revolving credit facilities to provide for borrowings, 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. 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.
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. 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.
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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. The inability to secure these agreements would materially adversely affect business, earnings, financial condition or cash flows.
Market based natural gas storage operations are subject to commodity price volatility which could result in variability in earnings and cash flows.
Spectra Energy has market based rates for some of its storage operations and sells its storage services based on natural gas market spreads and volatility.
If natural gas market spreads or volatility deviate from historical norms or there is significant growth in the amount of storage capacity available to natural gas markets, Spectra Energy’s approach to managing its market based storage contract portfolio may not protect it from significant variations in storage revenues.
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 NGLs and other products transported in the associated pipelines. Spectra Energy cannot predict the outcome of these claims or the effect they may ultimately have on business and operations.
Protecting against potential terrorist activities requires significant capital expenditures and a successful terrorist attack could adversely affect Spectra Energy’s business.
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 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 (MLPs) and Canadian income trusts. While the tax treatment for MLPs has not changed, on
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October 31, 2006, the Minister of Finance of Canada announced changes to the income tax treatment of “flow-through entities” in Canada, including income trusts. Legislation has now been enacted whereby 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. 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.
Spectra Energy might not be able to engage in desirable strategic transactions and equity issuances as a result of its separation from Duke Energy.
To preserve the tax-free treatment to Duke Energy of the distribution of Spectra Energy to the shareholders of Duke Energy, 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.
Poor investment performance of pension plan holdings and other factors affecting pension plan costs could unfavorably affect Spectra Energy’s earnings and liquidity.
Spectra Energy’s costs of providing non-contributory defined benefit pension plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and Spectra Energy’s required or voluntary contributions made to the plans. Without sustained growth in the pension plan investments over time to increase the value of Spectra Energy’s plan assets, and depending upon the other factors impacting Spectra Energy’s costs as listed above, Spectra Energy could be required to fund its plans with significant amounts of cash. Such cash funding obligations could have a material effect on Spectra Energy’s earnings and cash flows.
Item 1B. Unresolved Staff Comments.
None.
At December 31, 2007, 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 land. Except as described in Part I, Item 8. Financial Statements and Supplementary Data, Note 16 of Notes to Consolidated Financial Statements, none of Spectra Energy’s property was secured by mortgages or other material security interests at December 31, 2007.
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; Waltham, Massachusetts; Tampa, Florida; Halifax, Nova
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Scotia; Toronto, Ontario; and Nashville, Tennessee. For a description of its material properties, see Item 1. Business. Spectra Energy’s property, plant and equipment includes buildings, technical equipment and other equipment capitalized under capital lease agreements. For more details, refer to Note 14 of Notes to Consolidated Financial Statements.
For information regarding legal proceedings, including regulatory and environmental matters, see Notes 5 and 18 of Notes to Consolidated Financial Statements.
Item 4. Submission of Matters to a Vote of Security Holders.
At the Spectra Energy Annual Meeting of Shareholders on October 31, 2007, shareholders elected Fred J. Fowler, William T. Esrey, Dennis R. Hendrix and Pamela L. Carter to serve as Class I directors until the 2010 annual meeting of shareholders and until such Director’s successor is duly elected and qualified. Below is a tabulation of votes with respect to each nominee for director at the meeting:
| Nominee |
For | Against/ Withheld | ||
| Fred J. Fowler |
538,175,938 | 12,389,427 | ||
| William T. Esrey |
537,874,976 | 12,690,388 | ||
| Dennis R. Hendrix |
537,879,554 | 12,685,810 | ||
| Pamela L. Carter |
537,968,930 | 12,596,434 |
In addition, shareholders at the meeting also ratified the selection of Deloitte & Touche LLP to act as independent registered public accounting firm for Spectra Energy for 2007. There were 539,242,135 shares voted for the proposal, 6,642,193 shares voted against the proposal and 4,680,734 shares abstained.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Spectra Energy’s common stock is traded on the New York Stock Exchange under the symbol “SE.” As of February 19, 2008, there were 151,415 holders of record of Spectra Energy’s common stock and 525,281 beneficial owners. There was no market for Spectra Energy’s common stock in 2006 because all of the outstanding shares of common stock of Spectra Energy were owned by Duke Energy.
Common Stock Data by Quarter
| 2007 |
Dividends Per Common Share |
Stock Price Range(a) | |||||||
| High | Low | ||||||||
| First Quarter |
$ | 0.22 | $ | 30.00 | $ | 23.55 | |||
| Second Quarter |
$ | 0.22 | $ | 27.34 | $ | 24.89 | |||
| Third Quarter |
$ | 0.22 | $ | 27.73 | $ | 21.24 | |||
| Fourth Quarter |
$ | 0.22 | $ | 26.34 | $ | 23.98 | |||
| (a) | Stock prices represent the intra-day high and low stock price. |
Spectra Energy did not pay any cash dividends in 2006. 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. On January 4, 2008, Spectra Energy increased its quarterly dividend to $0.23 per common share.
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. There were no sales of unregistered equity securities during 2007.
Market Repurchases
Spectra Energy has not made any repurchases of shares of its common stock.
Item 6. Selected Financial Data.
The following selected financial data should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statement and Supplemental Data.
On January 2, 2007, 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 then wholly owned subsidiary, Spectra Capital. Spectra Capital is treated as the predecessor entity
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to Spectra Energy for financial statement reporting purposes. Accordingly, the information presented below for periods prior to 2007 is that of Spectra Capital. This information is not necessarily indicative of future performance or what the financial position and results of operations would have been if Spectra Energy had operated as a separate, stand-alone entity for periods presented prior to 2007.
| 2007 | 2006 | 2005 | 2004 | 2003(b) | ||||||||||||||
| (dollars in millions, except per-share amounts) | ||||||||||||||||||
| Statements of Operations(a) |
||||||||||||||||||
| Operating revenues |
$ | 4,742 | $ | 4,532 | $ | 9,454 | $ | 13,433 | $ | 11,937 | ||||||||
| Operating income |
1,442 | 1,245 | 1,853 | 1,327 | 103 | |||||||||||||
| Income (loss) from continuing operations |
944 | 936 | 1,409 | (707 | ) | (317 | ) | |||||||||||
| Net income (loss) |
957 | 1,244 | 674 | (114 | ) | (1,858 | ) | |||||||||||
| Ratio of Earnings to Fixed Charges |
3.1 | 3.1 | 4.3 | (c) | 1.7 | — | (d) | |||||||||||
| Common Stock Data |
||||||||||||||||||
| Earnings per share from continuing operations |
||||||||||||||||||
| Basic and Diluted |
$ | 1.49 | n/a | n/a | n/a | n/a | ||||||||||||
| Earnings per share—total |
||||||||||||||||||
| Basic and Diluted |
1.51 | n/a | n/a | n/a | n/a | |||||||||||||
| Dividends per share |
0.88 | n/a | n/a | n/a | n/a | |||||||||||||
| December 31, | ||||||||||||||||||
| 2007 | 2006 | 2005 | 2004 | 2003(c) | ||||||||||||||
| Balance Sheet |
||||||||||||||||||
| Total assets |
$ | 22,970 | $ | 20,345 | $ | 35,056 | $ | 37,183 | $ | 39,892 | ||||||||
| Long-term debt including capital leases, less current maturities |
8,345 | 7,726 | 8,790 | 11,288 | 13,655 | |||||||||||||
| (a) | Significant transactions reflected in the results include: the transfer of certain businesses to Duke Energy in December 2006 (see Item 8. Financial Statements and Supplementary Data, Note 1 of Notes to Consolidated Financial Statements), the 2006 transfer of DENA Midwestern assets to Duke Energy Ohio (see Note 9), the Crescent joint venture transaction and subsequent deconsolidation effective September 7, 2006 (see Note 9), the 2005 DENA disposition (see Note 9), the deconsolidation of DCP Midstream effective July 1, 2005 (see Note 3), the 2005 DCP Midstream sale of TEPPCO (see Note 3), a $1,030 million 2004 tax charge as a result of a reorganization relating to Duke Energy Americas, LLC, a $360 million pre-tax loss on the 2004 DENA sale of the Southeast plants and $2.8 billion of pre-tax charges related to DENA asset impairments in 2003. |
| (b) | As of January 1, 2003, Spectra Energy 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,” and Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” In accordance with the transition guidance for these standards, Spectra Energy recorded a net-of-tax and minority interest cumulative effect adjustment totaling $133 million for changes in accounting principles. |
| (c) | 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 3). |
| (d) | Earnings were inadequate to cover fixed charges by $500 million in 2003. |
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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 Item 8. Financial Statements and Supplementary Data.
EXECUTIVE OVERVIEW
2007 was a significant year for Spectra Energy, beginning with the spin-off from Duke Energy that was effective on January 2, 2007 allowing Spectra Energy to benefit from a sharper focus on core natural gas businesses and growth opportunities, with greater flexibility in accessing capital markets and responding to changes in the industry. Throughout 2007, Spectra Energy successfully performed on the strategies and objectives outlined to shareholders and the activities required to create and sustain a new, stand-alone corporate structure.
Spectra Energy reported net income of $957 million, and $1.51 of earnings per share for 2007, exceeding the employee incentive target earnings per share, primarily as a result of strong revenues for all Spectra Energy segments, including the effects of strong commodity prices for the Field Services and Empress operations. These positive results demonstrated the ability to capitalize on existing assets and to continue developing operational efficiencies. Expansion capital and investment expenditures for 2007 were $1.50 billion. These investments in Spectra Energy’s assets delivered on the organic growth and expansion activity discussed throughout the year as a key initiative for Spectra Energy. About $650 million of expansion projects were placed into service during the year, contributing to earnings growth in 2007 and beyond.
Another significant event was the formation and initial public offering in July 2007 of Spectra Partners, a newly formed midstream energy master limited partnership. Spectra Partners is a separate, publicly traded entity in which Spectra Energy retains an 83% interest. This transaction provided proceeds to Spectra Energy and will provide additional flexibility and growth options going forward.
Spectra Energy’s Strategy. 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 earnings and dividends per share and value to shareholders of Spectra Energy. Spectra Energy intends to accomplish this objective by executing the following overall business strategies:
| • | Deliver on 2008 financial commitments. |
| • | Enhance and solidify Spectra Energy’s profile and position as a premier natural gas infrastructure company. |
| • | Aggressively develop new opportunities and projects that add long-term shareholder value. |
| • | Enhance core competencies of customer service, reliability, cost management and compliance. |
| • | Build on the high-performance culture by focusing on safety, diversity, inclusion, leadership and employee development. |
| • | Focus on the future. Spectra Energy must be able to quickly change course when opportunities present themselves in order to be the effective and proactive partner that Spectra Energy’s customers expect— and the industry leader that Spectra Energy aspires to be. |
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.
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Spin-off from Duke Energy. On January 2, 2007, Duke Energy completed the spin-off of Spectra Energy. Duke Energy contributed 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 then wholly owned subsidiary, Spectra Capital. Duke Energy contributed its ownership interests in Spectra Capital to Spectra Energy and all of the outstanding common stock of Spectra Energy was distributed to Duke Energy’s shareholders. Duke Energy’s 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 Capital implemented an internal reorganization in which the operations and assets of Spectra Capital that were not associated with the natural gas businesses were contributed by Spectra Capital to Duke Energy or its subsidiaries. The contribution to Duke Energy included the International Energy business segment, Crescent Resources (a real estate business), the remaining portion of Spectra Capital’s business formerly known as DENA (Duke Energy North America), and other miscellaneous operations.
Following this internal reorganization and the distribution by Duke Energy to Spectra Energy, Spectra 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 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 Capital is treated as the predecessor entity of Spectra Energy for financial statement reporting purposes.
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 2006 and 2005. Transferred corporate services entities remain presented within continuing operations.
Effective upon the completion of the spin-off, Spectra Energy adopted new business segments to align the various operations of Spectra Energy with how the chief operating decision maker views the business: U.S. Transmission, Distribution, Western Canada Transmission & Processing and Field Services. All 2006 and 2005 information discussed herein has been re-cast to reflect these new business segments.
2007 Financial Results. Spectra Energy reported income from continuing operations of $944 million in 2007 compared to income from continuing operations of $936 million in 2006. The increase in income from continuing operations reflects higher earnings from the U.S. Transmission, Distribution and Western Canada Transmission & Processing operations, partly offset by higher interest expense and a higher effective tax rate. Highlights for 2007 include the following:
| • | U.S. Transmission’s earnings increased primarily as a result of strong revenues from pipeline and storage services and earnings associated with expansion and development projects; |
| • | Distribution results benefited from increased distribution margins, favorable storage market conditions and a strengthening Canadian dollar, partially offset by higher operating costs; |
| • | Western Canada Transmission & Processing’s earnings increased primarily as a result of very strong earnings at the Empress processing plant attributable to higher NGL prices and Canadian dollar exchange impacts, partially offset by declines in the BC Pipes and Field Services operations; |
| • | Field Services benefited from extremely strong NGL prices compared to 2006, especially in the fourth quarter; however, these commodity price benefits were offset by lower gathering and processing margins, higher operating costs and 2007 derivative losses at DCP Midstream Partners, LP (DCP Partners), a publicly traded MLP which is owned 35.4% by DCP Midstream; and |
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| • | Income From Discontinued Operations in the 2006 period was primarily composed of a gain on the sale of the 50% ownership interest in Crescent and net earnings from businesses transferred to Duke Energy prior to the spin-off. |
Significant Economic Factors for Spectra Energy’s Business. Spectra Energy’s regulated businesses are generally economically stable and are not significantly affected in the long-term by seasonal temperature variations and changing commodity prices. However, all of Spectra Energy’s businesses can be negatively affected in the long term by sustained downturns or sluggishness in the economy, which could affect long-term demand and 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.
Most 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 a decline in the volume of natural gas transported and distributed or gathered and processed at Spectra Energy’s plants, resulting in lower earnings and cash flows. This decline would primarily affect distribution revenues in the short term. Transmission revenues could be affected 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. Processing revenues are also affected by volumes of natural gas made available to the system, which is primarily driven by levels of natural gas drilling activity. Since late 2006, a reduction in Western Canadian drilling has occurred when compared to levels generally experienced during the previous three years. Overall, exploration and development activity in Spectra’s Western Canadian area has been relatively steady with increased activity around Spectra Energy’s McMahon and Pine River plants, and a decline in the Fort Nelson area of Northeast British Columbia.
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 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 effect 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 2007, the Canadian dollar strengthened significantly compared to the U.S. dollar, which has favorably affected earnings during these periods. Changes in this exchange rate or other of these factors are difficult to predict and may affect future results.
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Certain of Spectra Energy’s earnings are affected 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, 2006 and 2007, this trend in commodity prices may not be indicative of future prices. Management evaluates, on an ongoing basis, the risks associated with commodity price volatility and currently does not have any plans to enter into 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.
As Spectra Energy executes on its strategic objectives, expansion expenditures could average more than $1 billion per year over the next few years. Given the anticipated level of capital and investment expenditures in 2008 of approximately $2.4 billion, capital resources will include significant new long-term borrowings of approximately $1.5 billion in 2008. However, as a result of expansion earnings contributions and ongoing strong earnings performance anticipated in the existing operations, Spectra Energy expects to maintain a capital structure and liquidity profile that continues to support an investment-grade credit rating. 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 or its subsidiaries may increase the cost of borrowing or adversely affect the ability to access one or more sources of liquidity.
During the past two years, capital expansion projects have been exposed to cost pressures associated with the availability of skilled labor and the pricing of materials. As Spectra Energy moves forward with planned expansion opportunities, there will be continual focus on project management activities to address these pressures. Significant cost increases could negatively affect the returns ultimately earned on current and future expansions.
For further information related to management’s assessment of Spectra Energy’s risk factors, see Part I, Item 1A. Risk Factors.
RESULTS OF OPERATIONS
| 2007 | 2006 | 2005 | ||||||||
| (in millions) | ||||||||||
| Operating revenues |
$ | 4,742 | $ | 4,532 | $ | 9,454 | ||||
| Operating expenses |
3,313 | 3,334 | 8,123 | |||||||
| Gains on sales of other assets and other, net |
13 | 47 | 522 | |||||||
| Operating income |
1,442 | 1,245 | 1,853 | |||||||
| Other income and expenses |
649 | 736 | 1,668 | |||||||
| Interest expense |
633 | 605 | 675 | |||||||
| Minority interest expense |
71 | 45 | 511 | |||||||
| Earnings from continuing operations before income taxes |
1,387 | 1,331 | 2,335 | |||||||
| Income tax expense from continuing operations |
443 | 395 | 926 | |||||||
| Income from continuing operations |
944 | 936 | 1,409 | |||||||
| Income (loss) from discontinued operations, net of tax |
13 | 308 | (731 | ) | ||||||
| Income before cumulative effect of change in accounting principle |
957 | 1,244 | 678 | |||||||
| Cumulative effect of change in accounting principle, net of tax and minority interest |
— | — | (4 | ) | ||||||
| Net income |
$ | 957 | $ | 1,244 | $ | 674 | ||||
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2007 Compared to 2006
Operating Revenues. The $210 million, or 5%, increase was driven primarily by:
| • | the effects of the strong Canadian dollar on revenues at Western Canada Transmission & Processing and Distribution, and |
| • | the growth in revenues from higher demand for transmission and storage services and expansion projects. |
Operating Expenses. The $21 million decrease was driven primarily by:
| • | the capitalization of Northeast expansion project costs initially charged to operating expense. Spectra Energy expenses project development costs until such time as recovery of costs is determined to be probable. At that time, these costs are capitalized to property, plant and equipment and operating expenses are reduced, |
| • | a decrease in corporate costs primarily as a result of the reduced portfolio and activity of the U.S. captive insurance entity, partially offset by |
| • | the stronger Canadian dollar in 2007 compared to 2006. |
For a more detailed discussion of operating revenues and expenses, see the segment discussions that follow.
Gain on Sales of Other Assets and Other, net. The $34 million decrease was primarily due to the 2006 gains of $28 million on settlements of customers’ transportation contracts at U.S. Transmission.
Operating Income. The $197 million increase primarily reflects growth in revenues and lower expenses resulting from the net capitalization in 2007 of Northeast expansion project costs.
Other drivers to operating income are discussed above. For more detailed discussions, see the segment discussions that follow.
Other Income and Expenses. The $87 million decrease represents lower equity earnings from the Field Services segment and management fees billed by Spectra Energy to certain Duke Energy operations in 2006. These were partially offset by higher equity earnings on joint ventures that resulted primarily from capitalization of previously expensed project development costs.
Interest Expense. The $28 million increase was primarily due to interest costs capitalized in the prior year period related to capital projects of businesses that were transferred to Duke Energy.
Minority Interest Expense. The $26 million increase primarily resulted from higher earnings on Maritimes and Northeast pipeline, the formation in July 2007 of Spectra Partners and a decrease in the ownership of the operations of the Income Fund in the third quarter of 2006.
Income Tax Expense from Continuing Operations. The $48 million increase was a result of higher earnings from continuing operations in 2007 and tax benefits recorded in 2006. The effective tax rate was 32.0% for 2007 compared to 29.7% for the same period in 2006. The lower effective tax rate in 2006 resulted from a reduction in the unitary state tax rate as a result of Duke Energy’s merger with Cinergy Corp (Cinergy) and a 2006 tax benefit related to the impairment of an international investment no longer owned by Spectra Energy.
Income from Discontinued Operations, net of tax. Income from discontinued operations, net of tax was $13 million for 2007 and $308 million for 2006. These amounts represent results of operations and gains (losses) on dispositions related primarily to DENA’s assets and contracts outside the Midwestern and Southeastern
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United States, which are included in Other, as well as the operations of International Energy and Spectra Energy’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 transferring these businesses to Duke Energy in December 2006.
2006 Compared to 2005
Operating Revenues. The $4,922 million decrease was driven by the deconsolidation of DCP Midstream, effective July 1, 2005, which resulted from the transfer of a 19.7% interest in DCP Midstream to ConocoPhillips. This impact reduced reported revenues by $5,530 million. The remaining $608 million increase in revenues resulted from:
| • | the Empress System acquired in August 2005, |
| • | favorable Canadian dollar exchange impacts; and |
| • | 2005 mark-to-market losses resulting from increased commodity prices associated with cash flow hedges that hedged Field Services’ commodity price risk for a portion of 2005. |
Operating Expenses. The $4,789 million decrease was primarily driven by the $5,090 million decrease due to the deconsolidation of DCP Midstream, effective July 1, 2005. The remaining increase of $301 million resulted primarily from:
| • | the Empress System that was acquired in August 2005, |
| • | favorable Canadian dollar exchange impacts, and |
| • | higher pipeline and storage operating costs, increased pipeline integrity and project development expenses, and higher corporate costs allocated from Duke Energy to the U.S. Transmission segment, partially offset by |
| • | a 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 |
| • | a decrease associated with the 2005 recognition of unrealized losses as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk. |
For a more detailed discussion of operating revenues and expenses, see the segment discussions that follow.
Gain on Sales of Other Assets and Other, net. The $475 million decrease was primarily due to the $575 million pre-tax gain resulting from the DCP Midstream disposition transaction, partially offset by $70 million of net pre-tax losses at Commercial Power, principally the termination of structured power contracts in the Southeast region.
Operating Income. The $608 million decrease was primarily related to the $575 million gain in 2005 resulting from the DCP Midstream disposition transaction and the effects of the deconsolidation of DCP Midstream, effective July 1, 2005, which amounted to $440 million for 2005. Partially offsetting these decreases were a $250 million negative effect to operating income in 2005 related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk and a $70 million charge in 2005 related to the termination of former DENA structured power contracts in the Southeast region.
Other drivers to operating income are discussed above. For more detailed discussions, see the segment discussions that follow.
Other Income and Expenses. The $932 million 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’s limited partner interest in TEPPCO LP, partially offset by an increase in equity in earnings of unconsolidated affiliates due primarily to the deconsolidation of DCP Midstream effective July 1, 2005.
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Interest Expense. The $70 million decrease was primarily attributable to reduced interest expense associated with DCP Midstream, which was deconsolidated on July 1, 2005.
Minority Interest Expense. The $466 million decrease primarily resulted from the 2005 gain associated with the sale of TEPPCO GP and the effect of deconsolidation of DCP Midstream effective July 1, 2005.
Income Tax Expense from Continuing Operations. The $531 million decrease primarily resulted from lower pre-tax earnings, due primarily to the 2005 gains associated with the sale of TEPPCO GP and Spectra Energy’s limited partner interest in TEPPCO LP as discussed above. In addition, the effective tax rate decreased to 29.7% in 2006 from 39.7% in 2005. The lower effective tax rate in 2006 compared to 2005 resulted primarily from a 2006 benefit of $30 million due to a reduction in the unitary state tax rate as a result of Duke Energy’s merger with Cinergy, a 2006 tax benefit of $25 million related to the impairment of an investment in Bolivia and a 2005 tax expense related to the repatriation of foreign earnings.
Income (Loss) from Discontinued Operations, net of tax. Income (loss) from discontinued operations, net of tax was $308 million for 2006 and ($731) million for 2005. These amounts represent results of operations and gains (losses) on dispositions related primarily to 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’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 transferring these businesses to Duke Energy in December 2006.
The 2005 amount is primarily comprised of a $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 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 recognized after-tax losses of $330 million (approximately $400 million pre-tax) as the result of selling certain gas transportation and structured contracts related to DENA operations. These charges were offset by the recognition of after-tax gains of $160 million (approximately $200 million pre-tax) related to discontinued cash flow hedges associated with DENA operations and the net favorable operations of International Energy and Spectra Energy’s effective 50% interest in Crescent, and a number of businesses previously included in Other.
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest. During 2005, Spectra Energy 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 Financial Accounting Standards Board (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.
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 investments are managed centrally by Spectra Energy, 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’s ownership interest in operations without regard to financing methods or capital structures.
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As previously discussed, as a result of the reorganization and spin-off of Spectra Energy from Duke Energy, Spectra Energy now manages its business in four reportable segments: U.S. Transmission, Distribution, Western Canada Transmission & Processing and Field Services. The remainder of Spectra Energy’s business operations is presented as “Other,” and consists of unallocated corporate costs, wholly owned captive insurance subsidiaries, employee benefit plan assets and liabilities, and other miscellaneous activities. Comparative 2006 and 2005 data has been re-cast to conform the business segment disclosures to the new segment structure.
U.S. Transmission provides transportation and storage of natural gas for customers in various regions of the Eastern and Southeastern United States and the Maritime Provinces in Canada.
Distribution provides retail natural gas distribution service in Ontario, Canada, as well as natural gas transportation and storage services to other utilities and energy market participants in Ontario, Quebec and the United States.
Western Canada Transmission & Processing provides transportation of natural gas, natural gas gathering and processing services, and NGL extraction, fractionation, transportation, storage and marketing to customers in Western Canada and the northern tier of the United States.
Field Services gathers and processes natural gas, and fractionates, markets and trades NGLs. It conducts operations through DCP Midstream, which is owned 50% by Spectra Energy and 50% by ConocoPhillips. Field Services gathers raw natural gas through gathering systems located in eight major natural gas producing regions: Permian Basin, Mid-Continent, Rocky Mountain, East Texas-North Louisiana, Barnett Shale, Gulf Coast, South Texas and Central Texas.
Spectra Energy’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.
EBIT by Business Segment
| 2007 | 2006 | 2005 | ||||||||||
| (in millions) | ||||||||||||
| U.S. Transmission |
$ | 894 | $ | 816 | $ | 840 | ||||||
| Distribution |
322 | 265 | 277 | |||||||||
| Western Canada Transmission & Processing |
366 | 345 | 243 | |||||||||
| Field Services(a) |
533 | 569 | 1,946 | |||||||||
| Commercial Power(b) |
— | — | (70 | ) | ||||||||
| Total reportable segment EBIT |
2,115 | 1,995 | 3,236 | |||||||||
| Other |
(112 | ) | (77 | ) | (250 | ) | ||||||
| Total reportable segment and other EBIT |
2,003 | 1,918 | 2,986 | |||||||||
| Interest expense |
(633 | ) | (605 | ) | (675 | ) | ||||||
| Interest income and other(c) |
17 | 18 | 24 | |||||||||
| Consolidated earnings from continuing operations before income taxes |
$ | 1,387 | $ | 1,331 | $ | 2,335 | ||||||
| (a) | In July 2005, the ownership interest in DCP Midstream was reduced from 69.7% to 50%. Field Services segment data reflects 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 DENA’s sale of structured power contracts in December 2005. Commercial Power is not a current business segment of Spectra Energy. |
| (c) | Other includes foreign currency transaction gains and losses and additional minority interest expense not allocated to the segment results. |
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Minority interest expense as presented in the following segment-level discussions includes only minority interest expense related to EBIT of non-wholly owned entities. It does not include minority interest expense related to interest and taxes of those operations. The amounts discussed below include intercompany transactions that are eliminated in the consolidated financial statements.
U.S. Transmission
| 2007 | 2006 | Increase (Decrease) |
2005 | Increase (Decrease) |
|||||||||||||
| (in millions, except where noted) | |||||||||||||||||
| Operating revenues |
$ | 1,540 | $ | 1,503 | $ | 37 | $ | 1,453 | $ | 50 | |||||||
| Operating expenses |
|||||||||||||||||
| Operating, maintenance and other |
473 | 544 | (71 | ) | 431 | 113 | |||||||||||
| Depreciation and amortization |
217 | 203 | 14 | 207 | (4 | ) | |||||||||||
| Gains on sales of other assets and other, net |
8 | 44 | (36 | ) | 6 | 38 | |||||||||||
| Operating income |
858 | 800 | 58 | 821 | (21 | ) | |||||||||||
| Other income and expenses, net |
85 | 44 | 41 | 47 | (3 | ) | |||||||||||
| Minority interest expense |
49 | 28 | 21 | 28 | — | ||||||||||||
| EBIT |
$ | 894 | $ | 816 | $ | 78 | $ | 840 | $ | (24 | ) | ||||||
| Proportional throughput, TBtu(a) |
2,202 | 1,930 | 272 | 1,953 | (23 | ) | |||||||||||
| (a) | Trillion British thermal units. Revenues are not significantly affected by pipeline throughput fluctuations since revenues are primarily composed of demand charges. |
2007 Compared to 2006
Operating Revenues. The $37 million increase was driven by:
| • | a $32 million increase from higher demand for pipeline and storage services, primarily attributable to higher volumes and rates on Maritimes and Northeast Pipeline, and |
| • | a $21 million increase from expansion projects that were placed in service in 2006 and 2007, partially offset by |
| • | a $15 million decrease in processing revenues associated with pipeline operations, primarily from lower volumes compared to the 2006 period when utilization of the facilities was higher than normal due to hurricane effects. |
Operating, Maintenance and Other. The $71 million decrease was driven by:
| • | a $41 million decrease in project development costs charged to operations as a result of lower development costs incurred in 2007 and increased capitalization of Northeast expansion project costs in the 2007 period compared to 2006. In 2007, U.S. Transmission recognized a net reduction in operating expenses of $17 million, representing net development costs capitalized during that period, while 2006 included net project development costs of $24 million in operating expenses. |
| • | a $14 million decrease in operating costs primarily associated with lower plant processing fees as a result of a renegotiated contract, |
| • | a $12 million decrease in ad valorem taxes primarily as a result of favorable property valuations in certain states, and |
| • | an $11 million decrease resulting from higher recoveries of pipeline compressor fuel by the East Tennessee pipeline , partially offset by |
| • | a $16 million increase from higher labor and outside services costs for pipeline and storage operations. |
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Depreciation and Amortization. The $14 million increase was primarily driven by expansion projects placed into service in late 2006 and in 2007, an increase in the depreciation rate on Maritimes and Northeast Pipeline as part of a negotiated toll settlement that was effective on January 1, 2007, and Canadian dollar exchange effects on Maritimes and Northeast Pipeline (Canada) depreciation.
Gains on Sales of Other Assets and Other, net. The $36 million decrease was primarily due to a $28 million gain on the settlement of a customer’s transportation contracts in 2006.
Other Income and Expenses, net. The $41 million increase was a result of higher equity earnings from unconsolidated affiliates primarily attributable to the capitalization of project development costs for the Southeast Supply Header (SESH) and Gulfstream Phase IV projects.
Minority Interest Expense. The $21 million increase was driven primarily by higher revenues on Maritimes & Northeast Pipeline and earnings from Spectra Partners formed in July 2007.
EBIT. The $78 million increase was primarily due to strong revenues in all pipeline and storage businesses attributable to high demand for services, increased revenues from in-service expansion projects, and the capitalization of previously expensed development costs, partially offset by a gain on the settlement of a customer’s transportation contracts in 2006.
2006 Compared to 2005
Operating Revenues. The $50 million increase was driven by:
| • | a $27 million increase in processing revenues resulting from higher prices and volumes associated with hurricane activities, partially offset by lower transportation and storage revenues primarily from lower negotiated rates in 2006 and 2005 contract settlements, and |
| • | a $26 million increase from expansion projects primarily from the acquisition of the remaining 50% interest in Saltville in August 2005. |
Operating, Maintenance and Other. The $113 million increase was driven by:
| • | a $35 million increase primarily related to higher labor and outside service costs for pipeline and storage operations, |
| • | a $31 million increase in corporate costs allocations from Duke Energy, primarily as a result of the completion in 2006 of various business reorganizations by Duke Energy, including the merger with Cinergy, |
| • | a $15 million increase in plant processing fees for a new third party arrangement associated with hurricane plant outages, |
| • | a $12 million increase resulting from expansion projects primarily from the acquisition of the remaining 50% interest in Saltville in August 2005, |
| • | a $12 million increase in pipeline integrity expenses that are reflected in operating and maintenance expenses beginning in 2006 as a result of a FERC accounting order to charge such costs to expense, and |
| • | an $8 million increase in project development expenses, partially offset by |
| • | a $15 million decrease related to the resolution in 2006 of prior tax years’ ad valorem tax issues. |
Gains on Sales of Other Assets and Other, net. The $38 million increase was driven primarily by a $28 million gain in 2006 on the settlement of a customer’s transportation contracts and a $5 million gain on the sale of certain gathering assets in 2006.
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EBIT. The $24 million decrease was primarily due to increased operating and maintenance expenses, partially offset by higher revenue resulting from pipeline expansion projects, increased processing revenues associated with transportation and the gain on a settlement of a customer’s transportation contract.
Matters Affecting Future U.S. Transmission Results
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. NGL prices will continue to affect processing revenues that are associated with transportation services.
Distribution
| 2007 | 2006 | Increase (Decrease) |
2005 | Increase (Decrease) |
|||||||||||||
| (in millions, except where noted) | |||||||||||||||||
| Operating revenues |
$ | 1,899 | $ | 1,822 | $ | 77 | $ | 1,725 | $ | 97 | |||||||
| Operating expenses |
|||||||||||||||||
| Natural gas purchased |
1,059 | 1,091 | (32 | ) | 1,024 | 67 | |||||||||||
| Operating, maintenance and other |
361 | 322 | 39 | 296 | 26 | ||||||||||||
| Depreciation and amortization |
162 | 144 | 18 | 129 | 15 | ||||||||||||
| Gains on sales of other assets and other, net |
5 | — | 5 | — | — | ||||||||||||
| Operating income |
322 | 265 | 57 | 276 | (11 | ) | |||||||||||
| Other income and expenses, net |
— | — | — | 1 | (1 | ) | |||||||||||
| EBIT |
$ | 322 | $ | 265 | $ | 57 | $ | 277 | $ | (12 | ) | ||||||
| Number of customers |
1,289 | 1,268 | 21 | 1,249 | 19 | ||||||||||||
| Heating degree days |
7,070 | 6,489 | 581 | 7,273 | (784 | ) | |||||||||||
| Pipeline throughput, TBtu |
844 | 736 | 108 | 849 | (113 | ) | |||||||||||
2007 Compared to 2006
Operating Revenues. The $77 million increase was driven by:
| • | a $144 million increase in customer usage of natural gas primarily associated with winter weather that was approximately 9% colder than the previous year, |
| • | a $92 million increase caused by a stronger Canadian dollar, |
| • | a $21 million increase in storage and transmission revenues primarily due to favorable market conditions and growth of the transmission system, |
| • | a $19 million increase due to higher distribution rates approved by the regulator, and |
| • | a $12 million increase as a result of an earnings sharing requirement in 2006, partially offset by |
| • | a $213 million decrease from lower natural gas prices passed through to customers without a mark-up. |
Natural Gas Purchased. The $32 million decrease resulted from:
| • | a $213 million decrease related to lower natural gas prices passed through to customers, partially offset by |
| • | a $111 million increase in customer usage of natural gas associated with colder winter weather than the previous year, |
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| • | a $49 million increase caused by Canadian dollar exchange effects, and |
| • | a $24 million increase related to gas volumes used in operations. |
Operating, Maintenance & Other. The $39 million increase was primarily driven by:
| • | a $22 million increase caused by Canadian dollar exchange effects, and |
| • | a $13 million increase in labor costs. |
Depreciation and Amortization. The $18 million increase was primarily driven by completion of Phase I of the Dawn-Trafalgar transmission system expansion and Canadian dollar exchange effects.
EBIT. The $57 million increase primarily resulted from higher gas distribution margins, favorable storage market conditions and a stronger Canadian dollar, partially offset by higher operating and gas costs.
2006 Compared to 2005
Operating Revenues. The $97 million increase was driven primarily by:
| • | a $146 million increase from higher natural gas prices passed through to customers without a markup, |
| • | a $102 million increase caused by Canadian dollar exchange effects, |
| • | an $18 million increase as a result of growth in the number of customers, and |
| • | a $16 million increase in storage and transmission revenues primarily due to higher storage prices driven by warmer weather, partially offset by |
| • | a $186 million decrease primarily resulting from lower gas usage due to warmer weather compared to 2005. |
Natural Gas Purchased. The $67 million increase was driven primarily by:
| • | a $146 million increase from higher natural gas prices passed through to customers, |
| • | a $60 million increase caused by Canadian dollar exchange effects, and |
| • | a $10 million increase as a result of growth in the number of customers, partially offset by |
| • | a $157 million decrease primarily resulting from lower gas usage due to unseasonably warmer weather. |
Operating, Maintenance and Other. The $26 million increase was driven primarily by:
| • | a $19 million increase caused by Canadian dollar exchange effects, and |
| • | a $7 million increase primarily related to higher labor and benefit costs. |
Depreciation and Amortization. The $15 million increase was driven primarily by:
| • | a $6 million increase resulting from expansion projects placed into service, and |
| • | a $9 million increase caused by Canadian dollar exchange effects. |
EBIT. The $12 million decrease was primarily due to lower gas distribution margins associated with warmer weather and the resulting lower customer usage as compared with 2005, and higher operating costs. These decreases were partially offset by the Canadian dollar exchange effects.
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Matters Affecting Future Distribution Results
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 affected significantly by weather during the winter heating season. In addition, earnings over the last several years have benefited from the strengthening Canadian dollar and will be affected by future changes in the U.S./Canadian dollar exchange rates. As with all of Spectra Energy’s regulated entities, regulatory changes may affect future earnings.
Effective January 2008, a multi-year incentive rate structure became effective for Union Gas that provides for a slight increase in overall rates as compared to 2007, and includes an allowance for annual inflation adjustments, productivity and the impact of declining average use per customer.
Western Canada Transmission & Processing
| 2007 | 2006 | Increase (Decrease) |
2005 | Increase (Decrease) |
|||||||||||||
| (in millions, except where noted) | |||||||||||||||||
| Operating revenues |
$ | 1,304 | $ | 1,204 | $ | 100 | $ | 874 | $ | 330 | |||||||
| Operating expenses |
|||||||||||||||||
| Natural gas and petroleum products purchased |
362 | 349 | 13 | 216 | 133 | ||||||||||||
| Operating, maintenance and other |
421 | 392 | 29 | 306 | 86 | ||||||||||||
| Depreciation and amortization |
141 | 133 | 8 | 120 | 13 | ||||||||||||
| Gains on sales of other assets and other, net |
— | — | — | 6 | (6 | ) | |||||||||||
| Operating income |
380 | 330 | 50 | 238 | 92 | ||||||||||||
| Other income and expenses, net |
— | 25 | (25 | ) | 6 | 19 | |||||||||||
| Minority interest expense |
14 | 10 | 4 | 1 | 9 | ||||||||||||
| EBIT |
$ | 366 | $ | 345 | $ | 21 | $ | 243 | $ | 102 | |||||||
| Pipeline throughput, Tbtu |
596 | 594 | 2 | 636 | (42 | ) | |||||||||||
| Volumes processed, Tbtu |
709 | 730 | (21 | ) | 607 | 123 | |||||||||||
| Empress inlet volumes, Tbtu |
722 | 811 | (89 | ) | 354 | 457 | |||||||||||
2007 Compared to 2006
Operating Revenues. The $100 million increase was driven by:
| • | an $81 million increase caused by the strengthening Canadian dollar in 2007, and |
| • | a $33 million increase due to higher NGL prices associated with the Empress operations, partially offset by lower NGL sales volumes, mainly as a result of a plant maintenance turnaround in 2007, partially offset by, |
| • | an $18 million decrease resulting from lower processing volumes in the Fort Nelson area of northeastern British Columbia. |
Natural Gas and Petroleum Products Purchased. The $13 million increase included:
| • | a $21 million increase caused by Canadian dollar exchange effects in 2007, and |
| • | a $10 million decrease from lower volumes of natural gas purchased for the Empress facility, mainly as a result of a plant maintenance turnaround in 2007. |
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Index to Financial Statements
Operating, Maintenance and Other. The $29 million increase was driven by:
| • | a $25 million increase caused by Canadian dollar exchange effects in 2007, and |
| • | an $8 million increase due to higher plant maintenance turnaround costs in 2007 (Empress and Pine River) compared to 2006 (Fort Nelson), partially offset by |
| • | a $6 million decrease in plant fuel costs at the Empress facility, mainly as a result of a plant maintenance turnaround in 2007. |
Depreciation and Amortization. The $8 million increase was driven primarily by Canadian dollar exchange effects in 2007.
Other Income and Expenses and Other, net. The 2006 amount included a $15 million gain resulting from the Income Fund’s issuance of units for the purchase of Westcoast Gas Services Inc.
Minority Interest Expense. The $4 million increase was driven primarily by the decrease in the ownership of the operations of the Income Fund in the third quarter of 2006, from 58% to 46%, when additional trust units were sold by the Income Fund.
EBIT. The $21 million increase resulted from higher NGL prices and Canadian dollar exchange effects partially offset by lower natural gas processing volumes, and the 2006 gain resulting from the sale of Income Fund units.
2006 Compared to 2005
Operating Revenues. The $330 million increase was driven by:
| • | a $279 million increase in processing revenues, due primarily to the Empress System purchased in August 2005 and associated stronger commodity prices in 2006 compared to 2005, and |
| • | a $47 million increase due to Canadian dollar exchange rates favorably impacting revenues as a result of the strengthening Canadian dollar. |
Natural Gas Purchased. The $133 million increase was driven primarily by:
| • | a $131 million increase due to the Empress assets purchased in August 2005 and higher gas prices in 2006, and |
| • | a $7 million increase caused by Canadian dollar exchange rate effects. |
Operating, Maintenance and Other. The $86 million increase was driven primarily by:
| • | a $43 million increase due to the Empress assets purchased in August 2005, |
| • | a $25 million increase caused by Canadian dollar exchange rate effects, and |
| • | a $12 million increase related to higher labor and benefit costs and higher insurance premiums. |
Depreciation and Amortization. The $13 million increase was driven primarily by:
| • | a $9 million increase caused by Canadian dollar exchange rate effects, and |
| • | a $6 million increase due to Empress assets purchased in August 2005. |
Other Income and Expenses, net. The $19 million increase was driven primarily by a pre-tax SAB No. 51 gain of $15 million related to the Income Fund’s issuance of additional units.
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Minority Interest Expense. The $9 million increase resulted from the 2006 issuance of Trust Units in the Income Fund, which reduced Spectra Energy’s ownership in those operations to approximately 46% as of December 31, 2006.
EBIT. The $102 million increase was primarily due to the increase in processing earnings (primarily Empress System), the gain resulting from the Income Fund’s issuance of additional units and favorable Canadian dollar exchange effects from the strengthening Canadian dollar.
Matters Affecting Future Western Canada Transmission & Processing Results
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 benefit through optimizing the performance of the existing system and through organizational efficiencies. Earnings can fluctuate from period-to-period as a result of the timing of processing plant turnarounds that reduce revenues while the plant is out of service and increase operating costs as a result of the turnaround maintenance work. Western Canada Transmission and Processing’s 19 processing plants are generally scheduled for turnaround work every two to three years, with the work being staggered to prevent significant outages at any given time in a single geographic area. In addition, future earnings will be affected by the ability to renew service contracts and regulatory stability. Earnings from processing services will be affected by the ability to access additional natural gas reserves. In addition, the Empress NGL business will be affected by both gas flows and the effects of natural gas and NGL commodity prices.
During the period 2004 through 2006, Western Canada experienced historic levels of natural gas drilling activity. Beginning in late 2006, a reduction in Western Canadian drilling has been occurring when compared to the levels generally experienced during the previous three years. Overall, exploration and development activity in Western Canada Transmission & Processing’s core areas has been relatively steady, with strong continued throughputs in the Pine River and McMahon areas, with the most significant decline being in the Fort Nelson region of Northeast British Columbia. In addition, although the actual effects will not be known for some time, the Alberta government’s recently announced New Royalty Framework, proposed to be effective January 1, 2009, could affect certain of Westcoast’s Alberta operations. The operations in British Columbia could be positively affected by this change in royalties if producers reduce drilling in Alberta and increase drilling in British Columbia. Management continues to believe that low-to-moderate growth in Western Canada is reasonable over the long-term.
Field Services
| 2007 | 2006 | Increase (Decrease) |
2005 | Increase (Decrease) |
||||||||||||||
| (in millions, except where noted) | ||||||||||||||||||
| Operating revenues |
$ | — | $ | — | $ | — | $ | 5,530 | $ | (5,530 | ) | |||||||
| Operating expenses |
— | 5 | (5 | ) | 5,215 | (5,210 | ) | |||||||||||
| Gains on sales of other assets and other, net |
— | — | — | 577 | (577 | ) | ||||||||||||
| Operating income |
— | (5 | ) | 5 | 892 | (897 | ) | |||||||||||
| Equity in earnings of unconsolidated affiliates(a) |
533 | 574 | (41 | ) | 292 | 282 | ||||||||||||
| Other income and expenses, net |
— | — | — | 1,259 | (1,259 | ) | ||||||||||||
| Minority interest expense |
— | — | — | 497 | (497 | ) | ||||||||||||
| EBIT |
$ | 533 | $ | 569 | $ | (36 | ) | $ | 1,946 | $ | (1,377 | ) | ||||||
| Natural gas gathered and processed/transported, TBtu/d(b) |
6.8 | 6.8 | — | 6.8 | — | |||||||||||||
| NGL production, MBbl/d(c) |
363 | 361 | 2 | 353 | 8 | |||||||||||||
| Average natural gas price per MMBtu(d) |
$ | 6.86 | $ | 7.23 | $ | (0.37 | ) | $ | 8.59 | $ | (1.36 | ) | ||||||
| Average NGL price per gallon(e) |
$ | 1.11 | $ | 0.94 | $ | 0.17 | $ | 0.85 | $ | 0.09 | ||||||||
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| (a) | Includes Spectra Energy’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 |
2007 Compared to 2006
EBIT. Lower equity in earnings of $36 million were primarily the result of the following variances, each representing Spectra Energy’s 50% ownership portion of the earnings drivers at DCP Midstream:
| • | a $60 million decrease in marketing margins, including a $39 million loss on hedges related to commodity non-trading activity that were executed by DCP Partners, |
| • | a $59 million decrease in gathering and processing margins attributable to decreased natural gas and NGL volumes, primarily from the effects of severe weather, including downtime for repairs, as well as an increase in plant inefficiencies and contract renegotiations at less favorable terms, |
| • | a $56 million decrease resulting from higher operating costs of $24 million, administrative costs of $16 million and depreciation costs of $16 million primarily attributable to asset acquisitions, industry price pressures on materials, contract services and labor and higher repairs and maintenance costs, including $12 million in costs associated with DCP Midstream’s initiative to create stand-alone corporate functions, separate from the two partners of DCP Midstream, |
| • | an $18 million decrease due to higher net interest expense resulting from the increased debt associated with acquisitions in 2007, |
| • | a $14 million decrease as a result of a gain on the sale of gathering assets during 2006, and |
| • | a $9 million decrease resulting from decreased physical volume related to natural gas asset based trading and marketing, partially offset by |
| • | a $156 million increase from commodity sensitive processing arrangements, due to increased commodity prices, |
| • | a $15 million increase attributable to lower minority interest expense as a result of lower earnings at DCP Midstream Partners, and |
| • | a $6 million increase as a result of lower income tax expense primarily due to a 2006 adjustment to establish deferred tax liabilities for the new Texas margin tax. |
2006 Compared to 2005
In July 2005, Duke Energy caused a Spectra Energy subsidiary to complete the transfer of a 19.7% interest in DCP Midstream to ConocoPhillips, Spectra Energy’s co-equity owner in DCP Midstream, which reduced Spectra Energy’s ownership interest in DCP Midstream from 69.7% to 50% and resulted in Spectra Energy and ConocoPhillips becoming equal 50% owners in DCP Midstream. As a result of the DCP Midstream disposition transaction, Spectra Energy deconsolidated its investment in DCP Midstream and subsequently has accounted for DCP Midstream as an investment utilizing the equity method of accounting.
Operating Revenues. The $5,530 million decrease was due to the DCP Midstream disposition transaction and subsequent deconsolidation of DCP Midstream.
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Operating Expenses. The $5,210 million decrease was due to the DCP Midstream disposition transaction and subsequent deconsolidation of DCP Midstream. Operating expenses for 2005 were also affected by $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 $577 million decrease was due primarily to a pre-tax gain of $575 million on the DCP Midstream disposition transaction in the prior year.
Equity in Earnings of Unconsolidated Affiliates. The $282 million increase was due to Spectra Energy’s 50% of equity in earnings of DCP Midstream’s net income for the twelve months ended December 31, 2006 compared to equity in earnings of DCP Midstream’s net income for the six months ended December 31, 2005. DCP Midstream’ earnings during the twelve months ended December 31, 2006 continued to be favorably affected by increased NGL and crude oil prices 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 $1,259 million decrease was 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 had a pre-tax gain on the sale of its limited partner interest in TEPPCO LP of $97 million. TEPPCO GP and Spectra Energy’s limited partner interest in TEPPCO LP were each sold to Enterprise GP Holdings LP, an unrelated third party.
Minority Interest Expense. The $497 million 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 $1.1 billion, as discussed above.
EBIT. The $1,377 million decrease resulted primarily from the gain on sale of TEPPCO GP and Spectra Energy’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 compared to the prior year.
Supplemental Data
Below is supplemental information for DCP Midstream’s operating results subsequent to deconsolidation on July 1, 2005:
| Twelve Months Ended December 31, 2007 |
Twelve Months Ended December 31, 2006 |
Six Months Ended December 31, 2005 | |||||||
| (in millions) | |||||||||
| Operating revenues |
$ | 13,154 | $ | 12,335 | $ | 7,463 | |||
| Operating expenses |
11,959 | 11,063 | 6,814 | ||||||
| Operating income |
1,195 | 1,272 | 649 | ||||||
| Other income and expenses, net |
44 | 5 | 1 | ||||||
| Interest expense, net |
154 | 119 | 62 | ||||||
| Income tax expense |
11 | 23 | 4 | ||||||
| Net income |
$ | 1,074 | $ | 1,135 | $ | 584 | |||
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Matters Affecting 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 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, including but not limited to future commodity prices, drilling activity, inflation and the effects of severe weather. Management can provide no assurances regarding the effect of these factors.
Commercial Power
| 2007 | 2006 | Increase (Decrease) |
2005 | Increase (Decrease) | ||||||||||||
| (in millions) | ||||||||||||||||
| Operating revenues |
$ | — | $ | — | $ | — | $ | — | $ | — | ||||||
| Operating expenses |
— | — | — | — | — | |||||||||||
| Losses on sales of other assets and other, net |
— | — | — | (70 | ) | 70 | ||||||||||
| Operating income |
— | — | — | (70 | ) | 70 | ||||||||||
| Other income and expenses, net |
— | — | — | — | — | |||||||||||
| EBIT |
$ | — | $ | — | $ | — | $ | (70 | ) | $ | 70 | |||||
Commercial Power, which did not have any operations or net assets within Spectra Energy effective after December 31, 2005, consisted of a portion of the DENA operations, primarily merchant power plants and certain other power and gas contracts (collectively, the Southeast Plants). Spectra Energy sold the Southeast Plants in 2004 and the remaining contracts in 2005. The 2005 Losses on Sales of Other Assets and Other, Net represented the pre-tax charge related to the termination of structured power contracts in the Southwest region. Commercial Power is reported as a business segment in 2005 as a result of continuing involvement identified at the time of the sale.
Other
| 2007 | 2006 | Increase (Decrease) |
2005 | Increase (Decrease) |
||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Operating revenues |
$ | 31 | $ | 29 | $ | 2 | $ | (1 | ) | $ | 30 | |||||||||
| Operating expenses |
150 | 175 | (25 | ) | 288 | (113 | ) | |||||||||||||
| Gains on sales of other assets and other, net |
— | 2 | (2 | ) | 4 | (2 | ) | |||||||||||||
| Operating income |
(119 | ) | (144 | ) | 25 | (285 | ) | 141 | ||||||||||||
| Other income and expenses, net |
7 | 67 | (60 | ) | 35 | 32 | ||||||||||||||
| EBIT |
$ | (112 | ) | $ | (77 | ) | $ | (35 | ) | $ | (250 | ) | $ | 173 | ||||||
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2007 Compared to 2006
Operating Expenses. The $25 million decrease was primarily driven by:
| • | $25 million of lower operating expenses as a result of the reduced portfolio and activity of the U.S. captive insurance entity, and |
| • | $19 million of costs allocated from Duke Energy associated with the Cinergy merger in 2006, partially offset by |
| • | $11 of higher corporate costs related to higher employee incentives and benefits costs, and |
| • | $8 million of higher gas spin-off separation costs in 2007 ($23 million) compared to 2006 ($15 million). |
Other Income and Expenses, net. The $60 million decrease resulted from the management fees collected from certain Duke Energy operations in 2006 of $82 million, partially offset by the 2006 mark-to-market losses of $19 million for hedge positions associated with the earnings of the Field Services segment.
EBIT. The $35 million decrease was primarily due to management fees earned from a Duke Energy affiliate in 2006 partially offset by 2006 net hedge losses associated with the Field Services segment and lower 2007 net corporate costs.
2006 Compared to 2005
Operating Revenues. The $30 million increase was driven primarily by:
| • | a $130 million increase as a result of the prior year effect 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 offset by |
| • | 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 DENA’s hedge discontinuance in the Southeast. |
Operating Expenses. The $113 million 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 offset by |
| • | a $13 million increase primarily associated with Spectra Energy’s allocated share of Duke Energy’s costs to achieve the Cinergy merger in 2006. |
Other Income and Expenses, net. The $32 million increase was driven primarily by a $45 million favorable variance resulting from the realized and unrealized mark-to-market effects 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 in 2006 and $68 million in 2005 related to management fees charged to an unconsolidated affiliate.
EBIT. The $173 million increase was due primarily to the favorable variance related to realized and unrealized mark-to-market effects 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
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hurricanes and business interruption, partially offset by the prior year mark-to-market gain related to DENA hedge discontinuance in the Southeast.
Matters Affecting Future Other Results
Future Other results will continue to include corporate and business services provided for the operations of Spectra Energy, and will also include operating costs and self-insured losses associated with Spectra Energy’s captive insurance entities.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The application of accounting policies and estimates is an important process that continues to evolve as Spectra Energy’s operations change and accounting guidance is issued. Spectra Energy 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 discusses its critical accounting policies and estimates and other significant accounting policies with the Audit Committee of Spectra Energy.
Regulatory Accounting
Spectra Energy accounts for certain of its regulated operations under the provisions of Statement of Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, Spectra Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under generally accepted accounting principles (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 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 $889 million as of December 31, 2007 and $959 million as of December 31, 2006. Total regulatory liabilities were $568 million as of December 31, 2007 and $569 million as of December 31, 2006.
Impairment of Goodwill
Spectra Energy had goodwill balances of $3,948 million at December 31, 2007 and $3,507 million at December 31, 2006. Spectra Energy evaluates the impairment of goodwill under SFAS No. 142, “Goodwill and Other Intangible Assets.” The majority of Spectra Energy’s goodwill relates to the acquisition of Westcoast Energy, Inc. (Westcoast) in March 2002, which owns the majority of Spectra Energy’s Canadian operations. As of the acquisition date or upon a change in reporting units, Spectra Energy allocates goodwill to a reporting unit, which Spectra Energy defines as an operating segment or one level below an operating segment. As required by SFAS No. 142, Spectra Energy 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
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rate and estimated future cash flows. In estimating cash flows, Spectra Energy 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.
The long-term growth rates and projected cash flows of the gathering and processing activities in Western Canada are sensitive to assumptions around the prospects for natural gas exploration and drilling in the areas of British Columbia and Alberta that are in close proximity to Spectra Energy’s Western Canada assets (primarily in the western extent of the Western Canadian Sedimentary Basin). Although drilling slowed in 2006 and 2007 in certain of these areas (primarily in northeastern British Columbia), management believes that low-to-moderate growth in Spectra Energy’s operations is reasonable over the long-term. If this growth and expansion does not materialize in periods after 2010, the BC Field Services reporting unit could experience a decline in overall unit value, which could affect the ability to support the goodwill allocated to this unit.
Revenue Recognition
Revenues from the transportation, storage, distribution and sales of natural gas, and from the sales of NGLs, 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.
Pension and Other Post-Retirement Benefits
The calculations of pension and other post-retirement expense and liabilities require the use of numerous assumptions. Changes in these assumptions can result in different reported expense and liability amounts, and future actual experience can differ from the assumptions. Spectra Energy believes that the most critical assumptions for pension and other post-retirement benefits are the expected long-term rate of return on plan assets and the assumed discount rate. In addition, medical and prescription drug cost trend rate assumptions are critical for other post-retirement benefits. Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in Spectra Energy’s pension and post-retirement plans will impact future pension expense and liabilities.
LIQUIDITY AND CAPITAL RESOURCES
Known Trends and Uncertainties
Spectra Energy will rely primarily upon cash flows from operations and additional financing transactions to fund its liquidity and capital requirements for 2008. As of December 31, 2007, Spectra Energy had negative working capital of approximately $1,043 million. This balance includes short-term debt of $715 million and current maturities of long-term debt of $338 million which are expected to be financed through additional long-term borrowings. Spectra Energy also has access to four revolving credit facilities, with total combined capacities of approximately $2.7 billion. These facilities will be used principally as a back-stop for commercial paper programs.
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 Part I, Item 1A. Risk Factors for further discussion.
As Spectra Energy executes on its strategic objectives around organic growth and expansion projects, expansion expenditures could average more than $1 billion per year over the next few years. However, the timing and extent of these expenditures are likely to vary significantly from year to year. Given the anticipated levels of
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capital and investment expenditures in 2008 and over the next few years, capital resources will include significant long-term borrowings, including estimated new borrowings of approximately $1.5 billion in 2008. However, as a result of expansion earnings contributions and ongoing strong earnings performance expected in the existing operations, Spectra Energy expects to maintain a capital structure and liquidity profile that continues to support an investment-grade credit rating.
Operating Cash Flows
Net cash provided by operating activities increased $773 million to $1,467 million in 2007 compared to 2006. This change was driven primarily by:
| • | a $600 million payment to Barclays in 2006 in connection with the sale of certain commodity, energy marketing and management contracts of DENA, |
| • | approximately $400 million of net settlement cash outflows in 2006 related to remaining DENA contracts, and |
| • | capital expenditures of $322 million in 2006 for residential real estate, partially offset by |
| • | collateral of $540 million received by Spectra Energy in 2006 from Barclays, and |
| • | net payments in 2007 of $82 million to resolve certain litigation matters associated with discontinued LNG operations. |
Net cash provided by operating activities decreased $375 million to $694 million in 2006 compared to 2005. This change was driven primarily by:
| • | a $600 million payment to Barclays in 2006 in connection with the sale of certain commodity, energy marketing and management contracts of DENA, and |
| • | approximately $400 million of net settlement cash outflows in 2006 related to remaining DENA contracts, partially offset by |
| • | collateral of $540 million received by Spectra Energy in 2006 from Barclays. |
Investing Cash Flows
Net cash flows used in investing activities totaled $1,544 million in 2007 compared to net cash flows provided by investing activities of $1,569 million in 2006. This $3,113 million decrease was driven primarily by:
| • | approximately $2.0 billion in proceeds received in 2006 from the sales of equity investments and other assets, primarily the sale of DENA assets and an interest in Crescent, |
| • | a $672 million increase in capital and investment expenditures in 2007 associated with the U.S. Transmission, Distribution and Western Canada Transmission & Processing segments, |
| • | net purchases of available-for-sale securities of $145 million in 2007 compared to net sales of $485 million in 2006, and |
| • | proceeds totaling $254 million in the 2006 period from real estate sales activity of operations transferred to Duke Energy in December 2006, partially offset by |
| • | capital expenditures of $695 million in 2006 associated with the operations that were transferred to Duke Energy. |
Net cash flows provided by investing activities totaled $1,569 million in 2006 compared to $1,241 million in 2005. This $328 million increase was primarily driven by:
| • | net sales of available-for-sale securities of $485 million in 2006 compared to net purchases of $212 million in 2005, and |
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| • | 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 Western Canada Transmission & Processing, partially offset by |
| • | 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 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, |
| • | a decrease of $118 million in proceeds from real estate sales activity of operations transferred to Duke Energy in December 2006, and |
| • | $152 million of distributions from equity investees that were considered returns of equity in 2006 (primarily DCP Midstream), as compared to $383 million in 2005. |
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.
| 2007 | 2006 | 2005 | |||||||
| (in millions) | |||||||||
| Capital and Investment Expenditures |
|||||||||
| U.S. Transmission |
$ | 898 | $ | 343 | $ | 388 | |||
| Distribution |
369 | 315 | 172 | ||||||
| Western Canada Transmission & Processing |
195 | 132 | 370 | ||||||
| Field Services(a) |
— | — | 86 | ||||||
| International Energy |
— | 58 | 23 | ||||||
| Crescent(b) |
— | 185 | 244 | ||||||
| Other |
39 | 130 | 31 | ||||||
| Total consolidated |
$ | 1,501 | $ | 1,163 | $ | 1,314 | |||
| (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 exclude capital expenditures associated with residential real estate of $322 million for the period from January 1, 2006 through the date of the deconsolidation of Crescent (September 7, 2006) and $355 million in 2005 which are included in Capital Expenditures for Residential Real Estate within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows. |
Capital and investment expenditures for 2007 totaled $1,501 million and included $1,003 million for expansion projects and $498 million for maintenance and other projects. Spectra Energy projects 2008 capital and investment expenditures of approximately $2.4 billion, consisting of approximately $1.7 billion for U.S. Transmission, $0.4 billion for Distribution and $0.3 billion for Western Canada Transmission & Processing. Total projected 2008 capital and investment expenditures include approximately $1.9 billion of expansion capital expenditures and $0.5 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth.
Expansion capital expenditures in 2007 included several key projects placed into service in 2007, such as Algonquin’s Northeast Gateway deepwater connection with an LNG port and Union Gas’ Dawn-Trafalgar Phase II pipeline expansion that provides capacity primarily for ex-franchise customers under long-term contracts. Additionally, 2007 expansion capital included work on several other multi-year projects, including the Maritimes & Northeast, Texas Eastern and Southeast Supply Header projects described further below.
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Significant 2008 expansion projects are expected to include:
| • | Gulfstream—Phase III, expected to begin service in August 2008, includes approximately 35 miles of 30-inch pipeline. Phase IV includes about 18 miles of 20-inch pipe and increased compression and is expected to be in service in September 2008. Both projects will be serving the growing electricity needs of peninsular Florida. |
| • | Egan—Increase storage working capacity by 8 Bcf and expansion of the Texas Eastern interconnect for additional injection and withdrawal capabilities. This capacity is expected to be in service in August 2008 and will enable Egan to capture opportunities around new LNG supply along the Gulf Coast. |
| • | Maritimes & Northeast Phase IV—Expansion of capacity on the U.S. portion of the Maritimes & Northeast pipeline to move additional gas coming online in November 2008 from the Canaport LNG terminal in New Brunswick, Nova Scotia for deliveries into the Northeast United States. |
| • | Texas Eastern Transmission Time II—Involves new pipeline looping and compression to deliver an additional 150 million cubic feet per day (MMcf/d) from Lebanon, Ohio to New Jersey. Phase I of this project was placed into service December 1, 2007 and provides capacity from western Pennsylvania. Phase II will extend the capacity back to Lebanon, Ohio and is expected to be placed into service by November 2008. |
| • | Southeast Supply Header (SESH)—This joint venture with CenterPoint Energy, Inc. involves the construction of approximately 270 miles of new pipeline from the Perryville Hub in northern Louisiana to connect near Mobile, Alabama with the Gulfstream Natural Gas System. It will connect the natural gas supply basins of east Texas and north Louisiana to southeast markets and will interconnect with numerous interstate pipelines. This new pipeline is expected to be in-service in the summer of 2008. |
| • | Dawn-Trafalgar—Phase III of this Union Gas pipeline expansion consists of increased compression, expected to come on-line in November 2008, to create incremental transmission capacity for key power markets in Ontario and to support government initiatives to meet electric shortfalls with gas fired power plants. |
| • | Dawn Storage Deliverability—Provides for approximately 500 MMcf/d of incremental storage deliverability, expected to be in service in November 2008. Compression, wells and pipeline make up the new facilities. |
| • | Ramapo—An Algonquin capacity expansion, including 82,000 horsepower of new compression, to serve markets in the Northeast. Expected to be in-service in November 2008. |
Financing Cash Flows and Liquidity
Spectra Energy’s consolidated capital structure as of December 31, 2007, including short-term debt, was 55% debt, 40% stockholders’ equity and 5% minority interests.
Net cash used in financing activities totaled $191 million in 2007 compared to $2,454 million in 2006. This change was driven primarily by:
| • | approximately $2.4 billion of distributions to Duke Energy in 2006 primarily due to the Crescent joint venture transaction, |
| • | $230 million of net proceeds received in 2007 from Spectra Partners, as discussed further below, and |
| • | $366 million of commercial paper issued in 2007 compared to $261 million during 2006, partially offset by |
| • | a $335 million decrease in 2007 in proceeds from issuances of long-term debt, net of redemptions, and |
| • | dividends paid on common stock of $558 million in the 2007 period as compared with $89 million of advances made to Duke Energy in 2006. |
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Net cash used in financing activities was $2,454 million in 2006 compared to $2,341 million in 2005. This change was driven primarily by:
| • | a $221 million increase in distributions to parent, net of capital contributions, in 2006, due primarily to the 2006 proceeds from the Crescent JV transaction, and |
| • | the transfer of $118 million of cash held at Bison to Duke Energy during 2006, partially offset by |
| • | a $680 million increase in 2006 in net proceeds from the net issuances of long-term debt, notes payable and commercial paper, and |
| • | $89 million of advances made to Duke Energy in 2006 as compared with $242 million in 2005. |
Significant Financing Activities—2007
In July 2007, Spectra Energy completed the IPO of Spectra Partners and received total proceeds of approximately $345 million as a result of the transaction, including the debt issued as discussed below. Net cash of approximately $230 million was received by Spectra Partners upon closing of the IPO. Approximately $26 million of these proceeds was distributed to Spectra Energy, $194 million was used by Spectra Partners to purchase qualifying investment grade securities, and $10 million was retained by Spectra Partners to meet working capital requirements. Spectra Partners borrowed $194 million in term debt using the investment grade securities as collateral and borrowed an additional $125 million of revolving debt. Proceeds from these borrowings, totaling $319 million, were distributed to Spectra Energy. In conjunction with the public offering associated with Spectra Partners discussed further in Item 8. Financial Statements and Supplemental Data, Note 2 of Notes to Consolidated Financial Statements, Spectra Partners entered into a five-year $500 million facility that includes both term and revolving borrowing capacity. Obligations under the revolving portion of its credit facility are unsecured and the term borrowings are secured by qualifying investment grade securities in an amount equal to or greater than the outstanding principal amount of the loan.
In July 2007, Union Gas replaced the existing $400 million Canadian 364-day credit facility with a $500 million Canadian five-year credit facility.
In May 2007, Spectra Capital entered into a $1.5 billion credit facility that replaced two existing facilities that totaled $950 million.
Significant Financing Activities—2006
Union Gas issued 125 million Canadian dollars of 4.85% fixed-rate debentures ($108 million U.S. dollar equivalents as of the closing date) due in 2022, and 165 million Canadian dollars of 5.46% fixed-rate debentures ($148 million in U.S. dollar equivalents as of the issuance date) due in 2036.
In September 2006, prior to the completion of the partial sale of Crescent as discussed in Note 9 of Notes to Consolidated Financial Statements, 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 financing activity on the Consolidated Statements of Cash Flows. As a result of Spectra Energy’s deconsolidation of Crescent effective September 7, 2006, Crescent’s outstanding debt balance of $1,298 million was removed from Spectra Energy’s Consolidated Balance Sheets.
The Income Fund, a Canadian income trust 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’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 recognized a $15 million pre-tax gain on the sale of subsidiary stock. The proceeds from the offering plus the draw down of 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.
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During 2006, Spectra Energy advanced $89 million to Duke Energy and forgave advances to Duke Energy of $602 million. Additionally during 2006, Spectra Energy distributed $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’s sale of 50% of Crescent.
Significant Financing Activities—2005
In December 2005, the Income Fund was created which sold approximately 40% ownership in the Canadian Midstream operations for proceeds, net of underwriting discount, of $110 million. Also in 2005, Union Gas issued 200 million Canadian dollars of 4.64% fixed-rate debentures ($171 million in U.S. dollar equivalents as of the issuance date) due in 2016.
Spectra Energy received a $269 million capital contribution from Duke Energy, which Spectra Energy classified as an addition to Member’s Equity. In addition, Spectra Energy distributed $2.1 billion to Duke Energy to principally provide for funding for the execution of Duke Energy’s accelerated share repurchase transaction and to provide funding support for Duke Energy’s dividend. The distribution was primarily funded by Spectra Energy’s portion of the cash proceeds realized from the sale by DCP Midstream of TEPPCO GP and Spectra Energy’s sale of its limited partner interest in TEPPCO LP.
Available Credit Facilities and Restrictive Debt Covenants
| Outstanding at December 31, 2007 | |||||||||||||||||||||
| Expiration Date |
Credit Facilities Capacity |
Commercial Paper |
Term Loan |
Revolving Credit |
Letters of Credit |
Total | |||||||||||||||
| (in millions) | |||||||||||||||||||||
| Spectra Energy Capital, LLC |
2012 | $ | 1,500 | (a) | $ | 478 | $ | — | $ | — | $ | 16 | $ | 494 | |||||||
| Westcoast Energy, Inc. |
2011 | 200 | (b) | — | — | — | — | — | |||||||||||||
| Union Gas Limited |
2012 | 501 | (c) | 237 | — | — | — | 237 | |||||||||||||
| Spectra Energy Partners, LP |
2012 | 500 | (d) | — | 153 | 97 | — | 250 | |||||||||||||
| Total |
$ | 2,701 | $ | 715 | $ | 153 | $ | 97 | $ | 16 | $ | 981 | |||||||||
| (a) | Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65%. |
| (b) | 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%. |
| (c) | Credit facility is denominated in Canadian dollars totaling 500 million Canadian dollars and contains a covenant that requires the debt-to-total capitalization ratio to not exceed 75%. The facility also contains a provision which requires Union Gas to repay all borrowings under the facility for a period of two days during the second quarter of each year. |
| (d) | Contains a covenant requiring the borrower to collateralize the term loan with qualifying investment-grade securities in an amount equal to or greater than the outstanding principal amount of the loan. The terms of the credit facility allow for liquidation of collateral to fund capital expenditures or certain acquisitions provided that an equal amount of term loan is converted to a revolving loan. |
Spectra Energy’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, 2007, Spectra Energy 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.
Pursuant to certain debt agreements of Maritimes & Northeast Pipeline Limited Partnership (M&N LP) and Maritimes & Northeast Pipeline, L.L.C. (M&N LLC) (both approximately 78% owned by Spectra Energy), of
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which $501 million of notes and $286 million of bank loans were outstanding at December 31, 2007, a deliverability report on the status of natural gas reserves was provided to the lender’s collateral agent and trustee in late 2007. This report indicated that the deliverability of the natural gas reserves (excluding any consideration for LNG effects) specified in the debt agreements had begun to decline below the required throughput level. Accordingly, pursuant to the terms of the debt agreements, all cash available for distribution to equity holders from the M&N LP operations will be used prospectively to repay the bank loan of M&N LP and to escrow funds for the notes of M&N LP, and all cash available for distribution to equity holders from the M&N LLC operations will be used to escrow funds for the bonds of M&N LLC. Management expects this debt funding will not significantly affect Spectra Energy’s overall liquidity or capital plans.
Credit Ratings Summary as of February 18, 2008
| Standard and Poor’s |
Moody’s Investor Service |
Dominion Bond Rating Service | ||||
| Spectra Energy Capital, LLC(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 the current balance sheets. These credit ratings could be negatively affected if as a result of market conditions or other factors, they are unable to maintain the current balance sheet strength, or if earnings and cash flow outlook materially deteriorates.
Dividends. Spectra Energy currently anticipates a dividend payout ratio of approximately 60% of estimated annual net income per share of common stock. Spectra Energy expects to continue its policy of paying regular cash dividends. The declaration and payment of dividends are subject to the sole discretion of Spectra Energy’s Board of Directors and will depend upon many factors, including the financial condition, earnings and capital requirements of operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by the Board of Directors. On January 4, 2008, the Board of Directors increased the first quarter dividend to $0.23 per common share which will be paid on March 17, 2008. This dividend represents a 4.6% increase over the fourth quarter 2007 dividend.
Other Financing Matters. Spectra Energy and Spectra Capital have an automatic shelf registration statement on file with the SEC to register the issuance of an unspecified amount of various equity securities by Spectra Energy and various debt securities by Spectra Capital. In addition, as of December 31, 2007, subsidiaries of Spectra Energy had 810 million Canadian dollars (approximately U.S. $811 million) available under shelf registrations for issuances in the Canadian market. Of the 810 million Canadian dollars available under these shelf registrations, 500 million expires in May 2008 and 310 million expires in August 2008.
Off-Balance Sheet Arrangements
Spectra Energy 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 guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. See Item 8. Financial Statements and Supplementary Data, Note 19 of Notes to Consolidated Financial Statements for further discussion of guarantee arrangements.
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Most of the guarantee arrangements entered into by Spectra Energy 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 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’s operations. As such, if Spectra Energy discontinued issuing these guarantee arrangements, there would not be a material impact to the consolidated results of operations, financial position or cash flows.
In connection with the spin-off of Spectra Energy to Duke Energy shareholders, certain guarantees that were previously issued by Spectra Energy were assigned to, or replaced by, Duke Energy in 2006. For any remaining guarantees of other Duke Energy obligations, Duke Energy has indemnified Spectra Energy against any losses incurred under these guarantee arrangements.
Spectra Energy 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 Item 8. Financial Statements and Supplementary data, Notes 18 and 19 of Notes to Consolidated Financial Statements.
Contractual Obligations
Spectra Energy 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’s contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as Current Liabilities on the Consolidated Balance Sheets other than Current Maturities of Long-Term Debt. It is expected that the majority of current liabilities on the Consolidated Balance Sheets will be paid in cash in 2008.
Contractual Obligations as of December 31, 2007
| Payments Due By Period | |||||||||||||||
| Total | 2008 | 2009 & 2010 |
2011 & 2012 |
2013 & Beyond | |||||||||||
| (in millions) | |||||||||||||||
| Long-term debt(a) |
$ | 14,285 | $ | 932 | $ | 2,795 | $ | 1,950 | $ | 8,608 | |||||
| Capital leases(a) |
3 | 2 | 1 | — | — | ||||||||||
| Operating leases(b) |
231 | 53 | 74 | 50 | 54 | ||||||||||
| Purchase Obligations:(c) |
|||||||||||||||
| Firm capacity payments(d) |
1,199 | 234 | 230 | 196 | 539 | ||||||||||
| Energy commodity contracts(e) |
751 | 660 | 30 | 31 | 30 | ||||||||||
| Other purchase obligations(f) |
340 | 308 | 30 | 2 | — | ||||||||||
| Other long-term liabilities on the Consolidated Balance Sheets(g) |
56 | 56 | — | — | — | ||||||||||
| Total contractual cash obligations |
$ | 16,865 | $ | 2,245 | $ | 3,160 | $ | 2,229 | $ | 9,231 | |||||
| (a) | See Note 16 of Notes to Consolidated Financial Statements. Amounts include scheduled interest payments over the life of debt or capital lease. |
| (b) | See Note 18 of Notes to Consolidated Financial Statements. |
| (c) | Purchase obligations reflected in the Consolidated Balance Sheets have been excluded from the above table. |
| (d) | Includes firm capacity payments that provide Spectra Energy with uninterrupted firm access to natural gas transportation and storage. |
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| (e) | Includes contractual obligations to purchase physical quantities of NGLs and natural gas. Amounts include certain hedges per SFAS No. 133, “Accounting for Derivative Financial Instruments and Hedging Activities.” For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2007. |
| (f) | Includes contracts for software and consulting or advisory services. Amounts also include contractual obligations for engineering, procurement and construction costs for pipeline projects. Amounts exclude certain open purchase orders for services that are provided on demand, where the timing of the purchase can not be determined. |
| (g) | Includes estimated 2008 retirement plan contributions and estimated 2008 payments related to FIN 48 liabilities, including interest (see Notes 8 and 22 of Notes to Consolidated Financial Statements). Spectra Energy is unable to reasonably estimate the timing of FIN 48 liability and interest payments in years beyond 2008 due to uncertainties in the timing of cash settlements with taxing authorities. Excludes cash obligations for asset retirement activities (see Note 15). The amount of cash flows to be paid to settle the asset retirement obligations is not known with certainty as Spectra Energy may use internal resources or external resources to perform retirement activities. Amounts also exclude reserves for litigation, environmental remediation and self-insurance claims (see Note 18), annual insurance premiums that are necessary to operate the business (see Note 18) and regulatory liabilities (see Note 5) because Spectra Energy is uncertain as to the amount and/or timing of when cash payments will be required. Also, amounts exclude 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. |
Quantitative and Qualitative Disclosures About Market Risk
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.
Commodity Price Risk
Spectra Energy is exposed to the effect of market fluctuations in the prices of NGLs 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, primarily within DCP Midstream, 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. In the event the hedge is not effective, derivative gains and losses affect consolidated earnings. 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 and to frac-spreads in the Empress operations in Canada. Since NGL prices historically track crude oil prices, Spectra Energy discloses its NGL price sensitivities in terms of crude oil price changes. Based on a
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sensitivity analysis as of December 31, 2007 and 2006, at Spectra Energy’s forecasted NGL-to-oil price relationships, a $10 per barrel move in oil prices would affect Spectra Energy’s annual pre-tax earnings by approximately $135 million in 2008 ($120 million from Field Services and $15 million from U.S. Transmission) and approximately $170 million in 2007 ($150 million from Field Services and $20 million from U.S. Transmission). With respect to the frac-spread risk related to Empress processing and NGL marketing activities in Western Canada, as of December 31, 2007 and 2006, a $0.50 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 $16 million on an annual basis in 2008 and approximately $13 million in 2007. These hypothetical calculations consider estimated production levels, but do not consider other potential effects that might result from such changes in commodity prices. The actual effect of commodity price changes of Spectra Energy’s earnings could be significantly different than these estimates.
See also Item 8. Financial Statements and Supplementary Data, Notes 1 and 20 of Notes to Consolidated Financial Statements.
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, exploration and production companies, local distribution companies and utilities located throughout the U.S. and Canada. Spectra Energy has concentrations of receivables from these industry sectors. These concentrations of customers may affect Spectra Energy’s overall credit risk in that risk factors can negatively affect the credit quality of an entire sector. Credit risk associated with gas distribution services are primarily affected 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 manages cash and restricted cash positions to maximize value while assuring appropriate amounts of cash are available, as required. Spectra Energy invests its available cash in high-quality money market securities. Such money market securities are designed for safety of principal and liquidity, and accordingly, do not include equity-based securities. Spectra Energy has discontinued investing in both asset-backed commercial paper and auction-rate securities. One of Spectra Energy’s Canadian operating companies had a $17 million net investment in asset-backed commercial paper outstanding in Canada as of December 31, 2007 and is participating in a plan to restructure this paper. The restructuring agreement proposed as a part of this plan is currently being supported by many large Canadian financial institutions as well as several international banks. In addition, Spectra Energy had a $44 million investment in auction-rate securities outstanding as of December 31, 2007 that was sold by January 4, 2008.
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, 2007.
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.
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Interest Rate Risk
Spectra Energy is exposed to risk resulting from changes in interest rates as a result of its issuance of variable and fixed rate debt and investments in short and long-term securities. Spectra Energy manages 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 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 also Notes 1, 16, and 20 of Notes to Consolidated Financial Statements.
Based on a sensitivity analysis as of December 31, 2007, it was estimated that if market interest rates average 1% higher (lower) in 2008 than in 2007, interest expense, net of offsetting impacts in interest income, would increase (decrease) by $13 million. Comparatively, based on a sensitivity analysis as of December 31, 2006, had interest rates averaged 1% higher (lower) in 2007 than in 2006, it was estimated that interest expense, net of offsetting interest income, would have been approximately $8 million. These amounts were estimated by considering the effect of the hypothetical interest rates on variable-rate securities outstanding, adjusted for interest rate hedges, investments, and cash and cash equivalents outstanding as of December 31, 2007 and 2006. 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’s financial structure.
Equity Price Risk
Spectra Energy’s costs of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon, among other things, rates of return on plan assets. These plan assets expose Spectra Energy to price fluctuations in equity markets. In addition, Spectra’s captive insurance companies maintain various investments to fund certain business risks and losses. Those investments may, from time to time, include investments in equity securities.
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 effect of devaluation of the Canadian dollar.
A 10% devaluation in the Canadian dollar exchange rate as of December 31, 2007 in Spectra Energy’s currency exposure would result in an estimated net loss on the translation of local currency earnings of approximately $31 million to Spectra Energy’s Consolidated Statements of Operations in 2008. In addition, the Consolidated Balance Sheet would be negatively impacted by $511 million currency translation through the cumulative translation adjustment in Accumulated Other Comprehensive Income (AOCI) as of December 31, 2007 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.
The United States is not a signatory to the United Nations-sponsored Kyoto Protocol, which prescribes specific targets to reduce greenhouse gas (GHG) emissions for developed countries for the 2008-2012 period, and the federal government has not adopted a mandatory GHG emissions reduction requirement. While several bills have been introduced in the U.S. Congress that would impose GHG emissions constraints, final legislation has yet to advance.
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While Canada is a signatory to the United Nations-sponsored Kyoto Protocol, the federal government has confirmed that it will not achieve the targets within the timeframes specified. Instead, the federal government is expected to introduce in 2008 a regulatory framework mandating GHG reductions from large final emitters. The framework is expected to require GHG emissions intensity reductions of 18% beginning in 2010, with further reductions of 2% per year thereafter.
A number of states in the U.S., 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. In Canada, the province of British Columbia has introduced legislation establishing targets for the purpose of reducing GHG emissions to at least 33% less than 2007 levels by 2020 and to at least 80% less than 2007 levels by 2050. Specific emissions targets in British Columbia for 2012 and 2016 are expected to be established in 2008. In addition, in its February 2008 budget, the British Columbia government proposed a carbon tax that will apply, effective July 1, 2008, to the purchase or use of fossil fuels including natural gas consumed to process raw natural gas and in the operation of pipelines. Spectra Energy is currently assessing the potential impacts of this budget proposal. In 2007, the Province of Alberta adopted legislation which require existing large emitters (facilities releasing 100,000 tons or more of GHG emissions annually) to reduce their annual emissions intensity by 12% beginning July 1, 2007. The effect of this Alberta legislation did not materially affect consolidated results of operations, financial position or cash flows. The Alberta government is currently considering the next phase of development of its climate change action plan and additional regulations are anticipated. Legislation, regulations and programs mandating the reduction of GHG emissions in other provinces of Canada in which Spectra Energy has operations are still under development.
The key details of future GHG restrictions and related measures such as the proposed carbon tax are highly uncertain, and as such, 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 federal and provincial policies, Spectra Energy cannot estimate the potential effect of greenhouse gas policies on its future consolidated results of operations, financial position or cash flows. Spectra Energy will monitor the development of greenhouse gas regulatory policies in both countries as well as the states and provinces in which it operates 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, see Item 8. Financial Statements and Supplementary Data, Notes 5 and 18 of Notes to Consolidated Financial Statements.
New Accounting Pronouncements
The following new accounting pronouncements have been issued, but have not yet been adopted as of December 31, 2007:
SFAS No. 157, “Fair Value Measurements.” 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’s current practice for measuring and disclosing fair values under other accounting pronouncements that require or permit fair value measurements. For Spectra Energy, SFAS No. 157 is effective as of January 1, 2008 and must be applied prospectively except in certain cases. The adoption of SFAS No. 157 is not expected to materially affect Spectra Energy’s consolidated results of operations, financial position or cash flows.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” In February 2007, the FASB issued SFAS No. 159, which permits entities to choose to measure certain financial instruments at fair
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value. For Spectra Energy, SFAS No. 159 is effective as of January 1, 2008. Spectra Energy has determined it will not elect fair value measurements for financial assets and financial liabilities included in the scope of SFAS No. 159.
SFAS No. 141R, “Business Combinations.” In December 2007, the FASB issued SFAS No. 141R which replaces SFAS No. 141, “Business Combinations.” SFAS No. 141R requires the acquiring entity in a business combination to recognize all (and only) the assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed, and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 and cannot be early adopted.
SFAS No. 160, “Noncontrolling Interest in Consolidated Financial Statements.” In December 2007, the FASB issued SFAS No. 160 which requires all entities to report noncontrolling (minority) interests in subsidiaries as equity in the consolidated financial statements. SFAS No. 160 eliminates the diversity that currently exists in accounting for transactions between an entity and noncontrolling interests by requiring they be treated as equity transactions. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and early adoption is prohibited. Spectra Energy is currently evaluating the impact of adopting SFAS No. 160, and cannot currently estimate the effect it will have on its consolidated results of operations, financial position or cash flows.
EITF 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards.” In June 2007, the FASB Emerging Issues Task Force (EITF) reached a consensus that a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and are paid to employees for equity classified nonvested equity shares, nonvested equity share units, and outstanding equity share options should be recognized as an increase to additional paid-in capital. The amount recognized in additional paid-in capital for the realized income tax benefit from dividends on those awards should be included in the pool of excess tax benefits available to absorb tax deficiencies on share-based payment awards. EITF 06-11 will be applied prospectively to the income tax benefits that result from dividends on equity-classified employee share-based payment awards that are declared after December 31, 2007. The effect of adopting EITF 06-11 is not expected to be material to Spectra Energy’s consolidated results of operations, financial position or cash flows.
EITF 07-01, “Accounting for Collaborative Arrangements.” In December 2007, the FASB ratified a consensus reached by the EITF to define collaborative arrangements and to establish reporting requirements for transactions between participants in a collaborative arrangement and between participants in the arrangement and third parties. A collaborative arrangement is a contractual arrangement that involves a joint operating activity. These arrangements involve two (or more) parties who are both (a) active participants in the activity and (b) exposed to significant risks and rewards dependent on the commercial success of the activity. EITF 07-01 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. An entity should report the effects of applying EITF 07-01 as a change in accounting principle through retrospective application to all prior periods presented for all arrangements existing as of the effective date. Spectra Energy is currently evaluating the effect of adopting EITF 07-01, but does not believe it will have a material effect on its consolidated results of operations, financial position or cash flows.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk for discussion.
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Item 8. Financial Statements and Supplementary Data.
Management’s Annual Report on Internal Control over Financial Reporting
Spectra Energy’s management is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Spectra Energy’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes, in accordance with generally accepted accounting principles. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.
Spectra Energy’s management, including its Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of its internal control over financial reporting as of December 31, 2007 based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation, management concluded that Spectra Energy’s internal control over financial reporting was effective as of December 31, 2007.
Spectra Energy’s independent registered public accounting firm has audited and issued a report on the effectiveness of Spectra Energy’s internal control over financial reporting, which is included in their Report of Independent Registered Public Accounting Firm.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Spectra Energy Corp:
We have audited the accompanying consolidated balance sheets of Spectra Energy Corp and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’/member’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Spectra Energy Corp and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in
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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, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
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 Note 1 to the consolidated financial statements, in 2007 the Company changed its method of accounting for income tax positions as a result of adopting FIN 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109.
As discussed in Note 1 to the consolidated financial statements, on January 2, 2007, Duke Energy Corporation (“Duke Energy”) completed the spin-off of Spectra Energy Corp. Duke Energy contributed its ownership interests in Spectra Energy Capital, LLC to Spectra Energy Corp and all of the outstanding common stock of Spectra Energy Corp was distributed to Duke Energy’s shareholders.
/s/ Deloitte & Touche LLP
Houston, Texas
February 28, 2008
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SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per-share amounts)
| Years Ended December 31, | |||||||||||
| 2007 | 2006 | 2005 | |||||||||
| Operating Revenues |
|||||||||||
| Transportation, storage and processing of natural gas |
$ | 2,238 | $ | 2,126 | $ | 2,052 | |||||
| Distribution of natural gas |
1,664 | 1,623 | 1,553 | ||||||||
| Sales of natural gas and natural gas liquids |
601 | 531 | 5,547 | ||||||||
| Other |
239 | 252 | 302 | ||||||||
| Total operating revenues |
4,742 | 4,532 | 9,454 | ||||||||
| Operating Expenses |
|||||||||||
| Natural gas and petroleum products purchased |
1,416 | 1,435 | 5,821 | ||||||||
| Operating, maintenance and other |
1,161 | 1,202 | 1,338 | ||||||||
| Depreciation and amortization |
525 | 489 | 611 | ||||||||
| Property and other taxes |
209 | 208 | 228 | ||||||||
| Impairments and other charges |
2 | — | 125 | ||||||||
| Total operating expenses |
3,313 | 3,334 | 8,123 | ||||||||
| Gains on Sales of Other Assets and Other, net |
13 | 47 | 522 | ||||||||
| Operating Income |
1,442 | 1,245 | 1,853 | ||||||||
| Other Income and Expenses |
|||||||||||
| Equity in earnings of unconsolidated affiliates |
596 | 609 | 355 | ||||||||
| Gains (losses) on sales and impairments of equity method investments |
— | (3 | ) | 1,245 | |||||||
| Gain on sale of subsidiary stock |
— | 15 | — | ||||||||
| Other income and expenses, net |
53 | 115 | 68 | ||||||||
| Total other income and expenses |
649 | 736 | 1,668 | ||||||||
| Interest Expense |
633 | 605 | 675 | ||||||||
| Minority Interest Expense |
71 | 45 | 511 | ||||||||
| Earnings From Continuing Operations Before Income Taxes |
1,387 | 1,331 | 2,335 | ||||||||
| Income Tax Expense From Continuing Operations |
443 | 395 | 926 | ||||||||
| Income From Continuing Operations |
944 | 936 | 1,409 | ||||||||
| Income (Loss) From Discontinued Operations, net of tax |
13 | 308 | (731 | ) | |||||||
| Income Before Cumulative Effect of Change in Accounting Principle |
957 | 1,244 | 678 | ||||||||
| Cumulative Effect of Change in Accounting Principle, net of tax and |
— | — | (4 | ) | |||||||
| Net Income |
$ | 957 | $ | 1,244 | $ | 674 | |||||
| Common Stock Data |
|||||||||||
| Weighted-average shares outstanding |
|||||||||||
| Basic |
632 | n/a | (a) | n/a | (a) | ||||||
| Diluted |
635 | n/a | n/a | ||||||||
| Earnings per share from continuing operations |
|||||||||||
| Basic and Diluted |
$ | 1.49 | n/a | n/a | |||||||
| Earnings per share-total |
|||||||||||
| Basic and Diluted |
$ | 1.51 | n/a | n/a | |||||||
| Dividends per share |
$ | 0.88 | n/a | n/a | |||||||
| (a) | not applicable |
See Notes to Consolidated Financial Statements
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SPECTRA ENERGY CORP
CONSOLIDATED BALANCE SHEETS
(In millions)
| December 31, | ||||||
| 2007 | 2006 | |||||
| ASSETS |
||||||
| Current Assets |
||||||
| Cash and cash equivalents |
$ | 94 | $ | 299 | ||
| Receivables (net of allowance for doubtful accounts of $22 at December 31, 2007 and $13 at December 31, 2006) |
907 | 779 | ||||
| Inventory |
287 | 397 | ||||
| Other |
91 | 150 | ||||
| Total current assets |
1,379 | 1,625 | ||||
| Investments and Other Assets |
||||||
| Investments in and loans to unconsolidated affiliates |
1,780 | 1,618 | ||||
| Goodwill |
3,948 | 3,507 | ||||
| Other |
631 | 232 | ||||
| Total investments and other assets |
6,359 | 5,357 | ||||
| Property, Plant and Equipment |
||||||
| Cost |
18,154 | 15,639 | ||||
| Less accumulated depreciation and amortization |
3,854 | 3,245 | ||||
| Net property, plant and equipment |
14,300 | 12,394 | ||||
| Regulatory Assets and Deferred Debits |
932 | 969 | ||||
| Total Assets |
$ | 22,970 | $ | 20,345 | ||
See Notes to Consolidated Financial Statements
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SPECTRA ENERGY CORP
CONSOLIDATED BALANCE SHEETS
(In millions, except per-share amounts)
| December 31, | ||||||
| 2007 | 2006 | |||||
| LIABILITIES AND STOCKHOLDERS’ / MEMBER’S EQUITY |
||||||
| Current Liabilities |
||||||
| Accounts payable |
$ | 363 | $ | 246 | ||
| Notes payable and commercial paper |
715 | 349 | ||||
| Taxes accrued |
85 | 214 | ||||
| Interest accrued |
146 | 149 | ||||
| Current maturities of long-term debt |
338 | 550 | ||||
| Other |
775 | 850 | ||||
| Total current liabilities |
2,422 | 2,358 | ||||
| Long-term Debt |
8,345 | 7,726 | ||||
| Deferred Credits and Other Liabilities |
||||||
| Deferred income taxes |
2,883 | 2,980 | ||||
| Regulatory and other |
1,657 | 1,077 | ||||
| Total deferred credits and other liabilities |
4,540 | 4,057 | ||||
| Commitments and Contingencies |
||||||
| Minority Interests |
806 | 565 | ||||
| Stockholders’ / Member’s Equity |
||||||
| Preferred stock, $0.001 par, 22 million shares authorized, no shares outstanding at December 31, 2007 and 2006 |
— | — | ||||
| Common stock, $0.001 par, 1 billion shares authorized, 632 million and 1 thousand shares outstanding at December 31, 2007 and 2006, respectively |
1 | — | ||||
| Additional paid-in capital |
4,658 | — | ||||
| Retained earnings |
368 | — | ||||
| Member’s equity |
— | 4,598 | ||||
| Accumulated other comprehensive income |
1,830 | 1,041 | ||||
| Total stockholders’ / member’s equity |
6,857 | 5,639 | ||||
| Total Liabilities and Stockholders’ / Member’s Equity |
$ | 22,970 | $ | 20,345 | ||
See Notes to Consolidated Financial Statements
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SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
| Years Ended December 31, | ||||||||||||
| 2007 | 2006 | 2005 | ||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||||||
| Net income |
$ | 957 | $ | 1,244 | $ | 674 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
| Depreciation and amortization |
534 | 606 | 774 | |||||||||
| Gains on sales of investments in commercial and multi-family real estate, equity investments and other assets |
— | (509 | ) | (1,955 | ) | |||||||
| Impairment charges |
— | 48 | 159 | |||||||||
| Deferred income taxes |
110 | 104 | (240 | ) | ||||||||
| Minority interest |
71 | 60 | 538 | |||||||||
| Equity in earnings of unconsolidated affiliates |
(596 | ) | (712 | ) | (479 | ) | ||||||
| Distributions from unconsolidated affiliates |
569 | 707 | 473 | |||||||||
| Decrease (increase) in |
||||||||||||
| Receivables |
59 | 167 | (243 | ) | ||||||||
| Inventory |
147 | 115 | (74 | ) | ||||||||
| Other current assets |
14 | 1,288 | (435 | ) | ||||||||
| Increase (decrease) in |
||||||||||||
| Accounts payable |
(93 | ) | (690 | ) | 126 | |||||||
| Taxes accrued |
(61 | ) | 53 | 56 | ||||||||
| Other current liabilities |
(198 | ) | (461 | ) | 558 | |||||||
| Capital expenditures for residential real estate |
— | (322 | ) | (355 | ) | |||||||
| Cost of residential real estate sold |
— | 143 | 294 | |||||||||
| Other, assets |
(36 | ) | (796 | ) | 1,088 | |||||||
| Other, liabilities |
(10 | ) | (351 | ) | 106 | |||||||
| Cumulative effect of change in accounting principle |
— | — | 4 | |||||||||
| Net cash provided by operating activities |
1,467 | 694 | 1,069 | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||||||
| Capital expenditures |
(1,202 | ) | (987 | ) | (997 | ) | ||||||
| Investment in and loans to unconsolidated affiliates |
(285 | ) | (87 | ) | (23 | ) | ||||||
| Acquisitions, net of cash acquired |
(14 | ) | (89 | ) | (294 | ) | ||||||
| Purchases of available-for-sale securities |
(1,550 | ) | (9,290 | ) | (30,918 | ) | ||||||
| Proceeds from sales and maturities of available-for-sale securities |
1,405 | 9,775 | 30,706 | |||||||||
| Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable |
15 | 2,025 | 2,372 | |||||||||
| Proceeds from the sales of commercial and multi-family real estate |
— | 254 | 372 | |||||||||
| Settlement of net investment hedges and other investing derivatives |
— | (163 | ) | (296 | ) | |||||||
| Distributions from unconsolidated affiliates |
87 | 152 | 383 | |||||||||
| Other |
— | (21 | ) | (64 | ) | |||||||
| Net cash provided by (used in) investing activities |
(1,544 | ) | 1,569 | 1,241 | ||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||||||
| Proceeds from the issuance of long-term debt |
783 | 1,799 | 543 | |||||||||
| Payments for the redemption of long-term debt |
(981 | ) | (1,662 | ) | (840 | ) | ||||||
| Net increase in notes payable and commercial paper |
366 | 261 | 15 | |||||||||
| Distributions to minority interests |
(57 | ) | (304 | ) | (861 | ) | ||||||
| Contributions from minority interests |
9 | 247 | 779 | |||||||||
| Proceeds from issuances of subsidiary stock |
230 | 104 | 110 | |||||||||
| Dividends paid |
(558 | ) | — | — | ||||||||
| Distributions and advances to parent |
— | (2,450 | ) | (2,073 | ) | |||||||
| Cash associated with operations transferred to Duke Energy |
— | (427 | ) | — | ||||||||
| Other |
17 | (22 | ) | (14 | ) | |||||||
| Net cash used in financing activities |
(191 | ) | (2,454 | ) | (2,341 | ) | ||||||
| Effect of exchange rate changes on cash |
63 | (1 | ) | 6 | ||||||||
| Net decrease in cash and cash equivalents |
(205 | ) | (192 | ) | (25 | ) | ||||||
| Cash and cash equivalents at beginning of period |
299 | 491 | 516 | |||||||||
| Cash and cash equivalents at end of period |
$ | 94 | $ | 299 | $ | 491 | ||||||
| Supplemental Disclosures |
||||||||||||
| Cash paid for interest, net of amount capitalized |
$ | 627 | $ | 679 | $ | 833 | ||||||
| Cash paid for income taxes |
$ | 393 | $ | 238 | $ | 486 | ||||||
See Notes to Consolidated Financial Statements
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SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’/MEMBER’S
EQUITY AND COMPREHENSIVE INCOME
(In millions)
| Accumulated Other Comprehensive Income | |||||||||||||||||||||||||||||||||
| Common Stock |
Additional Paid-in Capital |
Retained Earnings |
Member’s Equity |
Foreign Currency Translation Adjustments |
Net Gains (Losses) on Cash Flow Hedges |
Minimum Pension Liability Adjustment |
Other | Total | |||||||||||||||||||||||||
| 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 of cash flow hedges into earnings(b) |
— | — | — | — | — | (1,025 | ) | — | — | (1,025 | ) | ||||||||||||||||||||||
| Minimum pension liability adjustment |
— | — | — | — | — | — | (40 | ) | — | (40 | ) | ||||||||||||||||||||||
| Net unrealized gains on SFAS 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 | ||||||||||||||||||||||||
| 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 losses on cash flow hedges(a) |
— | — | — | — | — | (6 | ) | — | — | (6 | ) | ||||||||||||||||||||||
| Reclassification of cash flow hedges into earnings(b) |
— | — | — | — | — | 39 | — | — | 39 | ||||||||||||||||||||||||
| Net unrealized gains on SFAS 115 securities(c) |
— | — | — | — | — | — | — | 14 | 14 | ||||||||||||||||||||||||
| Reclassification of SFAS 115 investments into earnings(d) |
— | — | — | — | — | — | — | (33 | ) | (33 | ) | ||||||||||||||||||||||
| Transfer of taxes on net investment hedge and other hedges from parent |
— | — | — | — | 62 | 7 | — | — | 69 | ||||||||||||||||||||||||
| Transfer of various entities to affiliate |
— | — | — | — | 205 | — | — | — | 205 | ||||||||||||||||||||||||
| Transfer of Midwestern assets to affiliate(e) |
— | — | — | — | — | 40 | — | — | 40 | ||||||||||||||||||||||||
| Minimum pension liability adjustment(f) |
— | — | — | — | — | — | (1 | ) | — | (1 | ) | ||||||||||||||||||||||
| Total comprehensive income |
1,677 | ||||||||||||||||||||||||||||||||
| Transfer of Midwestern assets to affiliate |
— | — | — | (1,462 | ) | — | — | — | — | (1,462 | ) | ||||||||||||||||||||||
| Transfer of Bison to affiliate |
— | — | — | (60 | ) | — | — | — | — | (60 | ) | ||||||||||||||||||||||
| Forgiveness of advances to parent |
— | — | — | (602 | ) | — | — | — | — | (602 | ) | ||||||||||||||||||||||
| Distribution to parent, net |
— | — | — | (796 | ) | — | — | — | — | (796 | ) | ||||||||||||||||||||||
| Distribution to parent associated with sale of Crescent |
— | — | — | (1,602 | ) | — | — | — | — | (1,602 | ) | ||||||||||||||||||||||
| Transfer of non-gas entities to affiliate |
— | — | — | (2,952 | ) | — | — | — | — | (2,952 | ) | ||||||||||||||||||||||
| Pension adjustment—SFAS 158 transition(g) |
— | — | — | — | — | — | 61 | (109 | ) | (48 | ) | ||||||||||||||||||||||
| Other, net |
— | — | — | (20 | ) | — | — | — | — | (20 | ) | ||||||||||||||||||||||
| December 31, 2006 |
— | — | — | 4,598 | 1,156 | (6 | ) | — | (109 | ) | 5,639 | ||||||||||||||||||||||
| Net income |
— | — | 957 | — | — | — | — | — | 957 | ||||||||||||||||||||||||
| Other comprehensive income |
|||||||||||||||||||||||||||||||||
| Foreign currency translation adjustments |
— | — | — | — | 877 | — | — | — | 877 | ||||||||||||||||||||||||
| Reclassification of cash flow hedges into earnings(b) |
— | — | — | — | — | (2 | ) | — | — | (2 | ) | ||||||||||||||||||||||
| Pension and benefits impact per SFAS 158 |
— | — | — | — | — | — | — | 14 | 14 | ||||||||||||||||||||||||
| Total comprehensive income |
1,846 | ||||||||||||||||||||||||||||||||
| Conversion to Spectra Energy Corp |
1 | 4,597 | — | (4,598 | ) | — | — | — | — | — | |||||||||||||||||||||||
| FIN 48 implementation |
— | — | (26 | ) | — | — | — | — | — | (26 | ) | ||||||||||||||||||||||
| Transfer of net assets and liabilities from Duke Energy |
— | 12 | — | — | — | — | — | (100 | ) | (88 | ) | ||||||||||||||||||||||
| Common stock dividends |
— | — | (558 | ) | — | — | — | — | — | (558 | ) | ||||||||||||||||||||||
| Effect of changing measurement date per SFAS 158 |
— | — | (5 | ) | — | — | — | — | — | (5 | ) | ||||||||||||||||||||||
| Stock-based compensation |
— | 49 | — | — | — | — | — | — | 49 | ||||||||||||||||||||||||
| December 31, 2007 |
$ | 1 | $ | 4,658 | $ | 368 | $ | — | $ | 2,033 | $ | (8 | ) | $ | — | $ | (195 | ) | $ | 6,857 | |||||||||||||
| (a) | Net of $3 million tax benefit in 2006 and $234 million tax expense in 2005. |
| (b) | Net of $1 million tax benefit in 2007, $20 million tax expense in 2006 and $584 million tax benefit in 2005. |
| (c) | Net of $8 million tax expense in 2006 and $10 million tax expense in 2005. |
| (d) | Net of $18 million tax benefit in 2006. |
| (e) | Net of $24 million tax expense in 2006. |
| (f) | Net of $27 million tax benefit in 2005. |
| (g) | Net of $27 million tax benefit in 2006. |
See Notes to Consolidated Financial Statements
72
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SPECTRA ENERGY CORP
Notes to Consolidated Financial Statements
| Page | ||||
| 1. | Summary of Operations and Significant Accounting Policies | 73 | ||
| 2. | Spectra Energy Partners, LP Initial Public Offering | 85 | ||
| 3. | Acquisitions and Dispositions | 86 | ||
| 4. | Business Segments | 87 | ||
| 5. | Regulatory Matters | 90 | ||
| 6. | Impairments | 92 | ||
| 7. | Other Income and Expenses, net | 92 | ||
| 8. | Income Taxes | 93 | ||
| 9. | Discontinued Operations | 95 | ||
| 10. | Earnings per Common Share | 99 | ||
| 11. | Marketable Securities | 100 | ||
| 12. | Goodwill | 101 | ||
| 13. | Investments in and Loans to Unconsolidated Affiliates and Related Party Transactions | 102 | ||
| 14. | Property, Plant and Equipment | 106 | ||
| 15. | Asset Retirement Obligations | 106 | ||
| 16. | Debt and Credit Facilities | 107 | ||
| 17. | Preferred and Preference Stock | 109 | ||
| 18. | Commitments and Contingencies | 109 | ||
| 19. | Guarantees and Indemnifications | 112 | ||
| 20. | Risk Management and Hedging Activities, Credit Risk, and Financial Instruments | 113 | ||
| 21. | Stock-Based Compensation | 116 | ||
| 22. | Employee Benefit Plans | 120 | ||
| 23. | Consolidating Financial Information | 131 | ||
| 24. | Quarterly Financial Data (Unaudited) | 135 |
1. Summary of Operations and Significant Accounting Policies
Nature of Operations. Spectra Energy Corp, through its subsidiaries and equity affiliates (collectively, Spectra Energy), owns and operates a large and diversified portfolio of complementary natural gas-related energy assets. Spectra Energy operates in three key areas of the natural gas industry: transmission and storage, distribution, and gathering and processing. Spectra Energy provides transportation and storage of natural gas to customers in various regions of the Northeastern and Southeastern United States, the Maritime Provinces in Canada and the Pacific Northwest in the United States and Canada, and in the province of Ontario, Canada. Spectra Energy also provides natural gas sales and distribution services to retail customers in Ontario, and natural gas gathering and processing services to customers in Western Canada. In addition, Spectra Energy owns a 50% interest in DCP Midstream, LLC (DCP Midstream), one of the largest natural gas gatherers and processors in the United States.
Spin-off from Duke Energy Corporation. On January 2, 2007, Duke Energy Corporation (Duke Energy) completed the spin-off of Spectra Energy. Duke Energy contributed the 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 then wholly owned subsidiary, Spectra Energy Capital, LLC (Spectra Capital). Duke Energy contributed its ownership interests in Spectra Capital to Spectra Energy and all of the outstanding common stock of Spectra Energy was distributed to Duke Energy’s shareholders. Duke Energy’s 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.
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In conjunction with the spin-off, on January 2, 2007, Duke Energy transferred to Spectra Energy the assets and liabilities, including related tax effects, associated with Spectra Energy’s employee benefits and captive insurance positions, as well as miscellaneous corporate assets and liabilities. The net effect of these non-cash transfers is reflected as an increase of $12 million to Additional Paid-in Capital and a decrease of $100 million to Accumulated Other Comprehensive Income in the Consolidated Statement of Stockholders’ Equity and Comprehensive Income during the year ended December 31, 2007. The following summarizes the effect on the Consolidated Balance Sheet in 2007 as a result of the transfers:
| Increase (Decrease) to Equity |
||||
| (in millions) | ||||
| Receivables |
$ | (9 | ) | |
| Other assets |
186 | |||
| Taxes accrued |
(5 | ) | ||
| Other current liabilities |
(65 | ) | ||
| Deferred income taxes |
94 | |||
| Other liabilities |
(289 | ) | ||
| Net equity decrease |
$ | (88 | ) | |
See also Notes 11 and 22 for further discussion of captive insurance and employee benefit plans.
Other Significant Changes. On April 1, 2006, Spectra Energy 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’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 entities, the results of operations of Bison do not qualify for discontinued operations treatment.
Additionally, in April 2006, Spectra Energy indirectly transferred to Duke Energy Ohio, Inc. (Duke Energy Ohio), its ownership interest in 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 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. The results of operations for 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 deconsolidated Crescent Resources, LLC (Crescent) due to a reduction in ownership and its inability to exercise control over Crescent. See Note 9 for further discussion. Crescent was accounted for as an equity method investment from the date of deconsolidation. Crescent was one of the entities contributed by Spectra Energy to Duke Energy in anticipation of the spin-off.
Effective July 1, 2005, Spectra Energy deconsolidated DCP Midstream, LLC (DCP Midstream) due to a reduction in ownership and its inability to exercise control over DCP Midstream. See Note 3 for further discussion. DCP Midstream has been subsequently accounted for as an equity method investment.
Basis of Presentation. The accompanying consolidated financial statements include the accounts of Spectra Energy Corp, its majority-owned subsidiaries where Spectra Energy has control and those variable interest entities, if any, where Spectra Energy is the primary beneficiary. As a result of the spin-off of the natural gas businesses of Duke Energy to Duke Energy’s shareholders, Spectra Capital is treated as the predecessor entity to Spectra Energy for financial statement reporting purposes. Accordingly, the 2006 and 2005 information presented herein for Spectra Energy is that of Spectra Capital. Additionally, in anticipation of the spin-off, and as
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further described in Note 9, Spectra Capital implemented an internal reorganization in December 2006 in which the operations and assets of Spectra Capital that were not associated with the natural gas businesses were contributed by Spectra Capital to Duke Energy or its subsidiaries. The 2006 and 2005 results of operations of most of these transferred businesses are included in Income From Discontinued Operations, Net of Tax in the accompanying Consolidated Statements of Operations. Corporate service companies that were transferred to Duke Energy in December 2006 are reported within continuing operations since corporate services continue to be provided at Spectra Energy to support operations. Information presented for 2006 and 2005 in the Consolidated Statements of Cash Flows does not include any reclassifications or adjustments to amounts historically reported for these transferred businesses.
Use of Estimates. To conform with generally accepted accounting principles (GAAP) in the United States, management makes estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and Notes to Consolidated Financial Statements. Although these estimates are based on management’s best available knowledge at the time, actual results could differ.
Reclassifications. As a result of the spin-off and the related realignment of Spectra Capital’s business segments as discussed in Note 4, the components of Operating Revenues on the consolidated Statements of Operations for the 2006 period have been reclassified to conform to the current reporting presentation. In addition, $112 million of balancing gas has been reclassified from Deferred Debits to Other Assets on the Consolidated Balance Sheet at December 31, 2006 to conform to the current reporting presentation.
Cash and Cash Equivalents. Highly liquid investments with original maturities of three months or less at the date of acquisition, except for the investments that are pledged as collateral against long-term debt as discussed below, are considered cash equivalents.
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 Ontario Energy Board (OEB). 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 OEB. The remaining inventory is recorded at cost, primarily using average cost. The components of inventory are as follows:
| December 31, | ||||||
| 2007 | 2006 | |||||
| (in millions) | ||||||
| Natural gas |
$ | 154 | $ | 290 | ||
| Materials and supplies |
108 | 90 | ||||
| Petroleum products |
25 | 17 | ||||
| Total inventory |
$ | 287 | $ | 397 | ||
Natural Gas Imbalances. The Consolidated Balance Sheets include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of imbalances is in-kind, changes in the balances do not have an effect on Spectra Energy’s Consolidated Statements of Cash Flows. Accounts Receivable includes $119 million as of December 31, 2007 and $113 million as of December 31, 2006. Other Current Liabilities includes $136 million as of December 31, 2007 and $118 million as of December 31, 2006, related to gas imbalances. Natural gas volumes owed to or by Spectra Energy are valued at natural gas market index prices as of the balance sheet dates.
Accounting for Risk Management and Hedging Activities and Financial Instruments. During 2005 and 2006, Spectra Energy used a number of different derivative and non-derivative instruments in connection
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with its commodity price, interest rate and foreign currency risk management activities, such as swaps, futures, forwards and options. In 2007, these derivative instruments were limited to interest rate positions, a small percentage of gas purchase hedges around the regulated operations at Union Gas Limited (Union Gas) and commodity derivatives at DCP Midstream. All derivative instruments not designated as hedges or qualifying for the normal purchases and normal sales exception under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, are recorded on the Consolidated Balance Sheets at fair value. Cash inflows and outflows related to derivative instruments, except 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 net investment hedges and derivatives related to other investing activities are a component of investing cash flows.
Where Spectra Energy’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,” are met, Spectra Energy presents its derivative assets and liabilities, and accompanying receivables and payables, on a net basis in the accompanying Consolidated Balance Sheets. Subsequent to the transfer of businesses to Duke Energy in 2006, Spectra Energy does not have any significant outstanding derivative instruments and does not participate in significant 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 recognized asset, liability or firm commitment (fair value hedge). For all hedge contracts, Spectra Energy prepares documentation of the hedge in accordance with SFAS No. 133 and assesses whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. Spectra Energy 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 Stockholders’/Member’s Equity and Comprehensive Income as Accumulated Other Comprehensive Income (AOCI) until earnings are affected by the hedged transaction. Spectra Energy 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 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. In the event the hedge is not effective, there is no offsetting gain or loss recognized in earnings. 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.
Fair value gains and losses on gas supply hedge positions at Union Gas are recognized as a regulatory asset or liability, as applicable, on the Consolidated Balance Sheets, pending recovery or refund as approved by the regulator as part of Union Gas’ gas cost recovery mechanisms.
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
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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.
Investments. Spectra Energy may actively invest a portion of its available cash and restricted cash balances in various financial instruments, including taxable or tax-exempt debt securities that frequently have stated maturities of 20 years or more. These instruments provide for a high degree of liquidity through features such as 7, 28, and 35 day auctions which allow for the redemption of the investments at their face amounts plus earned income. In addition, Spectra Energy invests in short-term money market securities, some of which are restricted due to debt collateral and insurance requirements. Spectra Energy has classified all investments that are debt securities with maturity dates over one year as available-for-sale under SFAS No. 115, “Accounting For Certain Investments in Debt and Equity Securities,” and they are carried at fair market value. Investments in money-market securities are accounted for at cost, as the carrying values approximate market values due to the short-term maturities, floating interest rates and minimal 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. The cost of securities sold is determined using the specific identification method. 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.
Goodwill. Spectra Energy evaluates goodwill for potential impairment under the guidance of SFAS No. 142, “Goodwill and Other Intangible Assets.” Under this standard, goodwill is subject to an annual test for impairment. Spectra Energy 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 performs the annual review for goodwill impairment at the reporting unit level, which Spectra Energy 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 completed its annual goodwill impairment test as of August 31, 2007 and no impairments were identified. Spectra Energy primarily uses a discounted cash flow analysis to determine fair value for each reporting unit. 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 incorporates expected long-term growth rates, regulatory stability, the ability to renew contracts, commodity prices (where appropriate), and foreign currency exchange rates, as well as other factors that affect its revenue, expense and capital expenditure projections.
Property, Plant and Equipment. Property, plant and equipment are stated at historical cost less accumulated depreciation. Spectra Energy capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The cost of renewals and betterments that extend the useful life or increase the expected output 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 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 3.14% for 2007, 3.32% for 2006 and 3.60% for 2005. See also “Allowance for Funds Used During Construction (AFUDC)” discussed below.
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When Spectra Energy 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.
Asset Retirement Obligations. Spectra Energy recognizes asset retirement obligations (AROs) in accordance with SFAS No. 143, “Accounting For Asset Retirement Obligations,” for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and FIN 47, “Accounting for Conditional Asset Retirement Obligations,” for conditional AROs 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. 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 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 uses the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” 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 Sheet. When an asset or asset group meets the SFAS No. 144 criteria for classification as held for sale within the Consolidated Balance Sheet, Spectra Energy does not retrospectively adjust prior period balance sheets to conform to current year presentation.
Spectra Energy 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 Discontinued Operations,” to determine whether components of Spectra Energy 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 must not have significant continuing involvement in the operations after the disposal (i.e. Spectra Energy 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’s ongoing operations (i.e. Spectra Energy 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
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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. Impairments for all other long-lived assets, excluding goodwill, are recorded as Impairment and Other Charges.
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 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. Undiscounted 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 accounts for certain of its regulated operations under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” The economic effects of regulation can result in a regulated company recording 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 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 periodically evaluates the applicability of SFAS No. 71, and considers factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, Spectra Energy may have to reduce its asset balances to reflect a market basis less than cost and write-off the associated regulatory assets and liabilities. See Note 5 for further discussion.
Captive Insurance Reserves. Prior to April 1, 2006, Spectra Energy had captive insurance subsidiaries which provided insurance coverage to Spectra Energy 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, as well as provisions for known claims which have been estimated on a claims-incurred basis. Incurred but not yet reported 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. Subsequent to April 1, 2006, Spectra Energy 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 were transferred to a new captive insurance subsidiary of Spectra Energy.
Prior to January 1, 2007, Spectra Energy’s captive insurance entities also had reinsurance coverage, which provided reimbursement to Spectra Energy for certain losses above a per incident and/or aggregate retention. Spectra Energy’s captive insurance entities also had an aggregate stop-loss insurance coverage, which provided reimbursement from third parties to Spectra Energy for its paid losses above certain per-line-of-coverage aggregate amounts during a policy year. Spectra Energy recognizes an insurance receivable for recovery of incurred losses under its insurance coverage once realization of the receivable is deemed probable.
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Guarantees. Spectra Energy 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.” In accordance with FIN 45, upon issuance or modification of a guarantee on or after January 1, 2003, Spectra Energy 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 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.”
Stock-Based Compensation. Effective January 1, 2006, Spectra Energy adopted the provisions of SFAS No. 123(R), “Share-Based Payment.” See Note 21 for further discussion. 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 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 report have not been restated. There were no modifications to outstanding stock options prior to the adoption of SFAS 123(R). Spectra Energy historically had been allocated its proportionate share of stock-based compensation expense from Duke Energy.
In 2005, Spectra Energy 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, “Accounting for Stock-Based Compensation” (SFAS No. 123). Since the exercise price for all stock options granted during these years 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 from the transportation, storage, distribution and sales of natural gas, and from the sales of NGLs 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, 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.
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 certain 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 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 $40 million in 2007 (an equity component of $22 million and an interest expense component of $18 million), $21 million in 2006 (an equity component of $11 million and an interest expense component of $10 million) and $17 million in 2005 (an equity component of $8 million and an interest expense component of $9 million).
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Preliminary Project Costs. Project development costs, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are initially included in operating expenses for U.S. rate-regulated enterprises that apply the principles of SFAS No. 71. If and when it is determined that recovery of such costs through regulated revenues of the completed project is probable, the inception-to-date costs of the project are recognized as Property, Plant and Equipment in accordance with the provisions of SFAS No. 71 and operating expenses are reduced.
Accounting For Sales of Stock by a Subsidiary. Spectra Energy accounts for sales of stock by a subsidiary under Staff Accounting Bulletin (SAB) No. 51, “Accounting for Sales of Stock of a Subsidiary.” 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 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 2006, Spectra Energy recognized a gain of $15 million related to the sale of securities of the Spectra Energy Income Fund (the Income Fund), formerly the Duke Energy Income Fund. See Note 3 for further discussion.
Income Taxes. Deferred income taxes are recognized for differences between the financial reporting and tax bases of assets and liabilities at enacted statutory tax rates in effect for the years in which the differences are expected to reverse. The effect on deferred taxes of a change in tax rates is recognized in income in the period that includes the enactment date. Actual income taxes could vary from these estimates due to future changes in income tax law or results from the final review of tax returns by federal, state or foreign tax authorities.
As a result of Duke Energy’s merger with Cinergy Corp (Cinergy), Spectra Energy and its subsidiaries entered into a tax sharing agreement with Duke Energy, effective April 1, 2006, where the separate return method was 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 would incur if Spectra Energy were a separate company filing its own tax return as a C-Corporation. Prior to entering into this tax sharing agreement, Spectra Energy was a pass-through entity for U.S. income tax purposes.
Spectra Energy adopted FIN 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FAS 109,” on January 1, 2007. The financial statement effects on tax positions are recognized in the period in which it is more-likely-than-not that the position will be sustained upon examination, the position is effectively settled or when the statute of limitations to challenge the position has expired. Interest and penalties related to unrecognized tax benefits are recorded as interest expense and other expense, respectively.
Segment Reporting. SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” establishes standards for a public company to report financial and descriptive information about its reportable operating segments in annual and interim financial reports. Operating segments are components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Two or more operating segments may be aggregated into a single reportable segment provided aggregation is consistent with the objective and basic principles of SFAS No. 131, if the segments have similar economic characteristics, and the segments are considered similar under criteria provided by SFAS No. 131. There is no aggregation within Spectra Energy’s defined business segments. The description of Spectra Energy’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, is presented in Note 4.
Foreign Currency Translation. The local currencies of Spectra Energy’s foreign operations, which represent Canadian operations subsequent to the spin-off from Duke Energy on January 2, 2007, have been determined to be their functional currencies, except for certain foreign operations (prior to 2007) included in discontinued operations whose functional currency has been determined to be the U.S. Dollar, based on an
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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 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.
Consolidated Statements of Cash Flows. Spectra Energy 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. 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 Unconsolidated Affiliates. Spectra Energy considers dividends received from unconsolidated affiliates which do not exceed cumulative equity in earnings subsequent to the date of investment to be 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 to be a return of investment and are classified as investing activities.
New Accounting Pronouncements — 2007. The following new accounting pronouncements were adopted during 2007 and the effect of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:
SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140.” 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 was effective for Spectra Energy 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. The adoption of SFAS No. 155 did not have an impact on Spectra Energy’s consolidated results of operations, cash flows or financial position.
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 has concluded there is a level of uncertainty with respect to the recognition in its financial statements. Spectra Energy implemented FIN 48 effective January 1, 2007. As discussed further in Note 8 the implementation resulted in a cumulative effect decrease of $26 million to beginning Retained Earnings on the Consolidated Statements of Stockholders’ Equity and Comprehensive Income. Uncertain tax positions on
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consolidated or combined tax returns filed by Duke Energy which are now indemnified by Spectra Energy, were recorded as payables to Duke Energy.
FSP No. FAS 123(R)-5, “Amendment of FASB Staff Position FAS 123(R)-1.” In October 2006, the FASB staff issued FSP No. FAS 123-5 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).” In August 2005, the FASB 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 GAAP. 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. The guidance in this FSP was effective for Spectra Energy as of January 1, 2007. The adoption of FSP No. FAS 123(R)-5 did not have a material effect on consolidated results of operations, financial position or cash flows.
FSP No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities.” In September 2006, the FASB 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 was effective for Spectra Energy as of January 1, 2007 and was applied retrospectively for all financial statements presented. The adoption of FSP No. AUG AIR-1 did not have an effect on Spectra Energy’s consolidated results of operations, financial position or cash flows.
2006. The following significant accounting pronouncements were adopted during 2006 and the effect of such adoption has been presented in the accompanying Consolidated Financial Statements:
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).” 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. Spectra Energy was 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. 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.
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 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 adopted the change in measurement date effective January 1, 2007 by re-measuring 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 was recognized, net of tax,
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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 were recognized, net of tax, as an adjustment to Other Comprehensive Income.
2005. The following significant accounting pronouncement was adopted during 2005 and the effect of such adoption has been presented in the accompanying Consolidated Financial Statements:
FIN 47 “Accounting for Conditional Asset Retirement Obligations.” In 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.” 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 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 $4 million.
Pending. The following new accounting pronouncements have been issued, but have not yet been adopted as of December 31, 2007:
SFAS No. 157, “Fair Value Measurements.” 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’s current practice for measuring and disclosing fair values under other accounting pronouncements that require or permit fair value measurements. For Spectra Energy, SFAS No. 157 is effective as of January 1, 2008 and must be applied prospectively except in certain cases. The adoption of SFAS No. 157 is not expected to materially affect Spectra Energy’s consolidated results of operations, financial position or cash flows.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” In February 2007, the FASB issued SFAS No. 159, which permits entities to choose to measure certain financial instruments at fair value. For Spectra Energy, SFAS No. 159 is effective as of January 1, 2008. Spectra Energy has determined it will not elect fair value measurements for financial assets and financial liabilities included in the scope of SFAS No. 159.
SFAS No. 141R, “Business Combinations.” In December 2007, the FASB issued SFAS No. 141R which replaces SFAS No. 141, “Business Combinations.” SFAS No. 141R requires the acquiring entity in a business combination to recognize all and only the assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed, requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination and further requires that acquisition-related costs, except for costs to issue debt or equity securities, be expensed in the period incurred. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 and cannot be early adopted.
SFAS No. 160, “Noncontrolling Interest in Consolidated Financial Statements.” In December 2007, the FASB issued SFAS No. 160 which requires all entities to report noncontrolling (minority) interests in subsidiaries as equity in the consolidated financial statements. SFAS No. 160 eliminates the diversity that currently exists in accounting for transactions between an entity and noncontrolling interests by requiring they be treated as equity transactions. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and early adoption is prohibited. Spectra Energy is currently evaluating the effect of adopting SFAS No. 160, and cannot currently estimate the effect it will have on its consolidated results of operations, financial position or cash flows.
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EITF 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards.” In June 2007, the FASB Emerging Issues Task Force (EITF) reached a consensus that a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and are paid to employees for equity classified nonvested equity shares, nonvested equity share units and outstanding equity share options should be recognized as an increase to additional paid-in capital. The amount recognized in additional paid-in capital for the realized income tax benefit from dividends on those awards should be included in the pool of excess tax benefits available to absorb tax deficiencies on share-based payment awards. EITF 06-11 will be applied prospectively to the income tax benefits that result from dividends on equity-classified employee share-based payment awards that are declared after December 31, 2007. The effect of adopting EITF 06-11 is not expected to be material to Spectra Energy’s consolidated results of operations, financial position or cash flows.
EITF 07-01 “Accounting for Collaborative Arrangements.” In December 2007, the FASB ratified a consensus reached by the EITF to define collaborative arrangements and to establish reporting requirements for transactions between participants in a collaborative arrangement and between participants in the arrangement and third parties. A collaborative arrangement is a contractual arrangement that involves a joint operating activity. These arrangements involve two (or more) parties who are both (a) active participants in the activity and (b) exposed to significant risks and rewards dependent on the commercial success of the activity. EITF 07-01 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. An entity should report the effects of applying EITF 07-01 as a change in accounting principle through retrospective application to all prior periods presented for all arrangements existing as of the effective date. Spectra Energy is currently evaluating the effect of adopting EITF 07-01, but does not believe it will have a material effect on its consolidated results of operations, financial position or cash flows.
2. Spectra Energy Partners, LP Initial Public Offering
In July 2007, Spectra Energy completed its initial public offering (IPO) of Spectra Energy Partners, LP (Spectra Partners), a newly formed midstream energy master limited partnership. Spectra Energy contributed to Spectra Partners 100% of the ownership of East Tennessee Natural Gas, LLC, 50% of the ownership of Market Hub Partners, LLC, including the Moss Bluff and Egan natural gas storage operations, and a 24.5% interest in Gulfstream Natural Gas System, LLC. Spectra Partners issued 11.5 million common units to the public in the offering, representing 17% of Spectra Partners’ outstanding equity. Spectra Energy retained an 83% equity interest in Spectra Partners, including its common units, subordinated units and a 2% general partner interest and received total proceeds of approximately $345 million as a result of the transaction, including the debt issued as discussed below. Net cash of approximately $230 million was received by Spectra Partners upon closing of the IPO. Approximately $26 million of these proceeds was distributed to Spectra Energy, $194 million was used by Spectra Partners to purchase qualifying investment grade securities, and $10 million was retained by Spectra Partners to meet working capital requirements. Spectra Partners borrowed $194 million in term debt using the investment grade securities as collateral and borrowed an additional $125 million of revolving debt. Proceeds from these borrowings, totaling $319 million, were distributed to Spectra Energy.
In accordance with the Securities and Exchange Commission (SEC) Staff Accounting Bulletin No. 51, “Accounting for Sales of Stock by a Subsidiary,” recognition of a gain associated with such a sale is only appropriate if the class of securities sold by the subsidiary does not contain any preference over the subsidiary’s other classes of securities. Since the common units of Spectra Partners have preferential cash distribution rights as compared to the subordinated units, Spectra Energy has deferred recognition of the gain associated with the sale of Spectra Partners common units until the subordinated units owned by Spectra Energy are converted into common units with rights equivalent to the remaining unitholders. The deferred gain totaled approximately $60 million at December 31, 2007 and is included in Regulatory and Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheet.
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3. Acquisitions and Dispositions
Acquisitions (excluding acquisitions made by discontinued operations that are discussed in Note 9). Spectra Energy 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,” is recorded as goodwill. The allocation of the purchase price may be adjusted if additional information is received during the allocation period, which generally does not exceed one year from the consummation date. This allocation period may be longer for certain income tax items.
In August 2005, U.S. Transmission acquired natural gas storage and pipeline assets in Southwest Virginia and an additional 50% interest in Saltville Gas Storage, L.L.C. from units of AGL Resources for $62 million. This transaction increased U.S. Transmission’s ownership percentage of Saltville Gas Storage, L.L.C. to 100%. No goodwill was recorded as a result of this acquisition.
In August 2005, Western Canada Transmission & Processing acquired the Empress System natural gas processing and NGL marketing business from ConocoPhillips for $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.
The pro forma results of operations for Spectra Energy as if those acquisitions occurred as of the beginning of the periods presented do not materially differ from reported results.
Dispositions (excluding dispositions made by discontinued operations that are discussed in Note 9). For the year ended December 31, 2006, the sale of other assets and businesses (which excludes discontinued operations that are discussed in Note 9) resulted in $80 million in proceeds and net pre-tax gains of $47 million recorded in Gains on Sales of Other Assets, net on the Consolidated Statements of Operations. Significant sales of other assets and businesses during 2006 are detailed as follows:
| • | U.S. 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 recorded in Gains on Sales of Other Assets, Net. In addition, U.S. Transmission’s sale of stock, received as consideration for the settlement of a customer’s transportation contract, resulted in proceeds of $29 million which is reflected in Other, Assets within Cash Flows from Operating Activities and a pre-tax gain of $29 million, of which $28 million was recorded in Gains on Sales of Other Assets, Net and $1 million was recorded in Other Income and Expenses, Net. See Note 11 for further discussion. |
| • | As a result of a settlement of a property insurance claim, U.S. Transmission received proceeds of $30 million and recognized a pre-tax gain of $10 million, which was recorded in Gains on Sales of Other Assets, Net. |
| • | In September 2006, the Income Fund created in 2005 sold 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 Issuances of Subsidiary Stock within Cash Flows from Financing Activities. The sale of these units reduced Spectra Energy’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 recognized a $15 million pre-tax SAB No. 51 gain on the sale of subsidiary stock, which is classified in Gain on Sale of Subsidiary Stock. The proceeds from the offering plus the draw down of 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. There were no deferred taxes recorded as a result of this transaction. |
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For the year ended December 31, 2005, the sale of other assets, busin